Supplemental Proposal for the Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule)

Note: EPA no longer updates this information, but it may be useful as a reference or resource.
  [Federal Register: June 10, 2004 (Volume 69, Number 112)]
[Proposed Rules]
[Page 32683-32772]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10jn04-17]
[[Page 32684]]

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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 72, 73, 74, 77, 78 and 96
[OAR-2003-0053; FRL-7667-1]
RIN 2060-AL76
 
Supplemental Proposal for the Rule To Reduce Interstate Transport 
of Fine Particulate Matter and Ozone (Clean Air Interstate Rule)

AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental notice of proposed rulemaking.

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SUMMARY: Today's action is a supplemental notice of proposed rulemaking 
(SNPR) to EPA's January 30, 2004 (69 FR 4566) notice of proposed 
rulemaking (NPR). The NPR requires certain States to submit State 
implementation plan (SIP) measures to ensure that emissions reductions 
are achieved as needed to mitigate transport of fine particulate matter 
(PM2.5) and/or ozone pollution and its main precursors--emissions of 
sulfur dioxide (SO₂) and oxides of nitrogen 
(NO_X)--across State boundaries. Today's action includes 
proposed rule language and supplemental information for the January 
2004 proposal, consisting of further discussion on establishing State-
level emissions budgets, proposed State reporting requirements and SIP 
approvability criteria, proposed model cap-and-trade rules, and a more 
thorough discussion of how this proposal interacts with existing Clean 
Air Act (CAA) programs and requirements.
    The EPA intends to produce a final rule by the end of calendar year 
2004.

DATES: Comments must be received on or before July 26, 2004. A public 
hearing will be held on June 3, 2004 in Alexandria, Virginia. Please 
refer to SUPPLEMENTARY INFORMATION for additional information on the 
comment period and the public hearing.

ADDRESSES: Submit your comments, identified by Docket ID No. OAR-2003-
0053, by one of the following methods:

    ? Federal eRulemaking Portal: http://www.regulations.gov.  
Follow the on-line instructions for submitting comments.
    ? Agency Web site: http://www.epa.gov/edocket. EDOCKET, 
EPA's electronic public docket and comment system, is EPA's preferred 
method for receiving comments. Follow the on-line instructions for 
submitting comments.
    ? E-mail: A-and-R-Docket@epa.gov.
    ? Mail: Air Docket, Clean Air Interstate Rule.
    ? Environmental Protection Agency, Mailcode: 6102T, 1200 
Pennsylvania Ave., NW., Washington, DC 20460.
    ? Hand Delivery: EPA Docket Center, 1301 Constitution 
Avenue, NW., Room B108, Washington, DC. Such deliveries are only 
accepted during the Docket's normal hours of operation, and special 
arrangements should be made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. OAR-2003-0053. 
The EPA's policy is that all comments received will be included in the 
public docket without change and may be made available online at 
http://www.epa.gov/edocket, including any personal information provided, 
unless the comment includes information claimed to be Confidential 
Business Information (CBI) or other information whose disclosure is 
restricted by statute. Do not submit information that you consider to 
be CBI or otherwise protected through EDOCKET, regulations.gov, or e-
mail. The EPA EDOCKET and the Federal regulations.gov websites are 
``anonymous access'' systems, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through EDOCKET or regulations.gov, your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses. For additional information about EPA's public 
docket visit EDOCKET on-line or see the Federal Register of May 31, 
2002 (67 FR 38102). For additional instructions on submitting comments, 
go to Unit I of the SUPPLEMENTARY INFORMATION section of this document.
    Docket: All documents in the docket are listed in the EDOCKET index 
at http://www.epa.gov/edocket. Although listed in the index, some 
information is not publicly available, i.e., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, is not placed on the Internet and will be 
publicly available only in hard copy form. Publicly available docket 
materials are available either electronically in EDOCKET or in hard 
copy at the EPA Docket Center, EPA West, Room B102, 1301 Constitution 
Avenue, NW., Washington, DC. The Public Reading Room is open from 8:30 
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The 
telephone number for the Public Reading Room is (202) 566-1744, and the 
telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For general questions concerning 
today's action, please contact Scott Mathias, U.S. EPA, Office of Air 
Quality Planning and Standards, Air Quality Strategies and Standards 
Division, C539-01, Research Triangle Park, NC, 27711, telephone (919) 
541-5310, e-mail at mathias.scott@epa.gov. For legal questions, please 
contact Howard J. Hoffman, U.S. EPA, Office of General Counsel, Mail 
Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, 
telephone (202) 564-5582, e-mail at hoffman.howard@epa.gov. For 
questions regarding air quality analyses, please contact Brian Timin, 
U.S. EPA, Office of Air Quality Planning and Standards, Emissions 
Modeling and Analysis Division, D243-01, Research Triangle Park, NC, 
27711, telephone (919) 541-1850, e-mail at timin.brian@epa.gov. For 
questions regarding emissions reporting requirements, please contact 
Bill Kuykendal, U.S. EPA, Office of Air Quality Planning and Standards, 
Emissions Modeling and Analysis Division, Mail Code D205-01, Research 
Triangle Park, NC, 27711, telephone (919) 541-5372, e-mail at 
kuykendal.bill@epa.gov. For questions regarding the model cap-and-trade 
programs, please contact Sam Waltzer, U.S. EPA, Office of Atmospheric 
Programs, Clean Air Markets Division, Mail Code 6204J, 1200 
Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343-
9175, e-mail at waltzer.sam@epa.gov. For questions regarding analyses 
required by statutes and executive orders, please contact Linda 
Chappell, U.S. EPA, Office of Air Quality Planning and Standards, Air 
Quality Strategies and Standards Division, Mail Code C339-01, Research 
Triangle Park, NC, 27711, telephone (919) 541-2864, e-mail at 
chappell.linda@epa.gov.

[[Page 32685]]

SUPPLEMENTARY INFORMATION: 

I. Additional Information on Submitting Comments

A. How Can I Help EPA Ensure That My Comments Are Reviewed Quickly?

    To expedite review of your comments by Agency staff, you are 
encouraged to send a separate copy of your comments, in addition to the 
copy you submit to the official docket, to Douglas Solomon, U.S. EPA, 
Office of Air Quality Planning and Standards, Emissions Modeling and 
Analysis Division, Mail Code C304-01, Research Triangle Park, NC, 
27711, telephone (919) 541-4132, e-mail iaqrcomments@epa.gov.

B. What Should I Consider as I Prepare My Comments for EPA?

    1. Submitting CBI. Do not submit this information to EPA through 
EDOCKET, regulations.gov or e-mail. Clearly mark the part or all of the 
information that you claim to be CBI. For CBI information in a disk or 
CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as 
CBI and then identify electronically within the disk or CD ROM the 
specific information that is claimed as CBI. In addition to one 
complete version of the comment that includes information claimed as 
CBI, a copy of the comment that does not contain the information 
claimed as CBI must be submitted for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2. Send or deliver information 
identified as CBI only to the following address: Roberto Morales, U.S. 
EPA, Office of Air Quality Planning and Standards, Mail Code C404-02, 
Research Triangle Park, NC 27711, telephone (919) 541-0880, e-mail at 
morales.roberto@epa.gov, Attention Docket ID No. OAR-2003-0053.
    2. Tips for Preparing Your Comments. When submitting comments, 
remember to:
    i. Identify the rulemaking by docket number and other identifying 
information (subject heading, Federal Register date and page number).
    ii. Follow directions--The agency may ask you to respond to 
specific questions or organize comments by referencing a Code of 
Federal Regulations (CFR) part or section number.
    iii. Explain why you agree or disagree; suggest alternatives and 
substitute language for your requested changes.
    iv. Describe any assumptions and provide any technical information 
and/or data that you used.
    v. If you estimate potential costs or burdens, explain how you 
arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
    vi. Provide specific examples to illustrate your concerns, and 
suggest alternatives.
    vii. Explain your views as clearly as possible, avoiding the use of 
profanity or personal threats.
    viii. Make sure to submit your comments by the comment period 
deadline identified.

II. Regulated Entities

    This action does not propose to directly regulate emissions 
sources. Instead, it proposes to require States to revise their SIPs to 
include control measures to reduce emissions of NO_X and 
SO₂. The proposed emissions reductions requirements that 
would be assigned to the States are based on controls that are known to 
be highly cost effective for EGUs.

III. Website for Rulemaking Information

    The EPA has also established a web site for this rulemaking at 
http://www.epa.gov/interstateairquality/ which will include the 
rulemaking actions and certain other related information that the 
public may find useful.

IV. Public Hearing

    The EPA will hold a public hearing on today's proposal on June 3, 
2004. The hearing will be held at the following location: Holiday Inn 
Select, Old Town Alexandria, 480 King Street, Alexandria, Virginia 
22314, Telephone: (703) 549-6080.
    The public hearing will begin at 9 a.m. and continue until 5 p.m., 
or later if necessary depending on the number of speakers. Oral 
testimony will be limited to 5 minutes per commenter. The EPA 
encourages commenters to provide written versions of their oral 
testimonies either electronically (on computer disk or CD-ROM) or in 
paper copy. Verbatim transcripts and written statements will be 
included in the rulemaking docket. If you would like to present oral 
testimony at the hearing, please notify Joann Allman, U.S. EPA, Office 
of Air Quality Planning and Standards, C539-02, Research Triangle Park, 
NC 27711, telephone (919) 541-1815, email allman.joann@epa.gov, by May 
31, 2004. For updates and additional information on the public hearing 
please check EPA's website for this rulemaking.
    The public hearing will provide interested parties the opportunity 
to present data, views, or arguments concerning the proposed rule. The 
EPA may ask clarifying questions during the oral presentations, but 
will not respond to the presentations or comments at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as any oral comments and 
supporting information presented at a public hearing.

Outline

I. Background
II. State-by-State Emissions Reduction Requirements and EGU Budgets
    A. SO₂ Emissions Budgets
    B. NO_X Emissions Budgets
III. Integration With Clean Air Act Programs
    A. SIP Criteria
    B. What Changes are EPA Proposing for Emissions Reporting 
Requirements?
    C. Acid Rain Program
    D. NO_X SIP Call
    E. How Would Emissions Trading Under This Proposed Rule Relate 
to Regional Haze?
    F. Tribal Issues
IV. Model Cap-and-Trade Rules
    A. Background and Purpose of the Model Rules
    B. Elements of the Proposed NO_X and SO₂ 
Model Trading Rules, Subparts AA through HH and AAA through HHH
V. Clarifications to January 30, 2004 Proposal
    A. Scope of the Proposed Action
    B. Summary of Control Costs
    C. Source of Cost Information
    D. Judicial Review Under Clean Air Act Section 307
VI. Statutory and Executive Order Reviews
VII. Proposed Rule Text

I. Background

    The EPA's January 30, 2004 proposal (69 FR 4566-4650) \1\ proposed 
to find that emissions of SO₂ and NO_X from 28 
States and DC, and emissions of NO_X alone from 25 States and 
DC, violate the provisions of CAA section 110(a)(2)(D) by contributing 
significantly to nonattainment downwind of, respectively, the annual 
PM2.5 and the 8-hour ozone national ambient air quality standards (NAAQS).
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    \1\ The EPA signed the January 30, 2004 proposal on December 17, 
2003 and made it immediately available to the public on EPA's Web 
site at http://www.epa.gov/interstateairquality.

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    As a result, EPA proposed to require SIP revisions containing 
measures to ensure that necessary emissions reductions are achieved. 
The EPA proposed SIP submittal deadlines and other aspects of the SIP 
submittals. Further, the January 2004 proposal identified the 
appropriate NO_X and SO₂ emissions that each of 
the affected jurisdictions would be required to eliminate. The January 
2004 proposal explained that the affected States could choose to 
control any sources they wish to achieve those emissions reductions, 
and generally discussed the methodologies for determining the

[[Page 32686]]

appropriate amount of emissions reductions on a State-by-State basis. 
The January 2004 proposal further explained that the emissions 
reductions may most cost effectively be achieved by controls on 
electric generating units (EGUs), and, in particular, through 
regionwide cap-and-trade programs for EGUs. Accordingly, the January 
2004 proposal indicated the methods for determining the allowable 
amounts of SO₂ and NO_X emissions from EGUs, and 
offered a sketch of the model cap-and-trade programs, which EPA would 
offer to administer, that States may choose to adopt.
    This supplemental proposal fills in certain gaps in the January 
2004 proposal and revises it or its supporting information in specific 
ways. This section of the SNPR provides background on this supplemental 
proposal and summarizes its contents.
    Section II of the SNPR provides additional detail on establishing 
State emissions budgets (i.e., emissions reduction requirements) on 
which we are requesting comment.
    Section III discusses the interaction of the January 2004 proposal 
with existing CAA programs and requirements. It includes discussion of 
specific SIP criteria and emissions reporting requirements. It also 
discusses the interactions of the Clean Air Interstate Rule (CAIR) with 
the Acid Rain Program that also requires SO₂ and 
NO_X emissions reductions--and the NO_X SIP Call, 
which was a 1998 rulemaking that required States in the eastern U.S. to 
submit SIPs reducing NO_X emissions to eliminate adverse 
impacts on the 1-hour ozone NAAQS. Section III also discusses the 
implications of the CAIR for compliance with regional haze 
requirements. It also discusses Tribal issues in more detail than was 
contained in the January 2004 proposal.
    Section IV provides significant additional details concerning the 
EPA's model cap-and-trade program for EGUs.
    Section V includes clarifications to the January 2004 proposal with 
respect to preamble language that was unclear, incomplete, 
inadvertently omitted, or inadvertently incorrect.
    Section VI addresses the required statutory and executive order 
reviews for this SNPR.
    Section VII lists the sections of proposed regulatory language that 
are included in today's supplemental proposal. (The January 2004 
proposal was not accompanied by proposed regulatory language).
    Under CAA section 307(d)(1)(J), the procedural requirements of 
section 307(d) apply to this proposal. In addition, under section 
307(d)(1)(U), the Administrator is authorized to include any other 
actions as covered under section 307(d). The EPA is including the 
proposals in today's SNPR and in the January 2004 proposal under 
section 307(d)(1)(U). Therefore, section 307(d) applies to all 
components of the rulemaking of which this action is a component.

II. State-by-State Emissions Reductions Requirements and EGU Budgets

    In the January 2004 proposal, EPA proposed methods for determining 
the SO₂ and NO_X emission reduction requirements 
or budgets for each affected State. Today, EPA proposes corrections to 
the proposals in the NPR. Additional details are included in a 
technical support document.\2\
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    \2\ See, ``State Emission Budget Calculation Technical Support 
Document for the Proposed Clean Air Interstate Rule (May 2004).''
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    Also, in the January 2004 proposal, EPA proposed methods for 
determining regionwide budgets. Today, EPA is not proposing any 
revisions to this methodology. However, in this SNPR, EPA used updated 
heat input data to develop the regionwide NO_X budgets, 
yielding a slight difference.
    The choice of method to impose State-by-State emissions reduction 
requirements makes little difference in terms of the overall cost of 
the regionwide SO₂ and NO_X reductions. Assuming 
that allowances can be freely traded, the cap-and-trade framework would 
encourage least-cost compliance over the entire region, an outcome that 
does not depend on the relative levels of individual State budgets.

A. SO₂ Emissions Budgets

1. Approaches for Integrating SO₂ Title IV Program with CAIR
    As described in the January 2004 proposal and other places in 
today's preamble, EPA is proposing to integrate the title IV Acid Rain 
SO₂ program with the trading program proposed in today's 
notice by requiring facilities to comply with this rule using title IV 
allowances at a greater retirement ratio than one allowance for every 
one ton of emissions. In the January 2004 proposal, EPA proposed that, 
to meet the 65 percent reduction required under Phase II (which begins 
in 2015), EPA could require an affected EGU to retire three 2015 and 
beyond allowances for every ton of SO₂ that it emits. 
However, this 3-to-1 ratio results in slightly more reductions than EPA 
has proposed are necessary to eliminate the significant contribution of 
an upwind State. This section of today's SNPR proposes two basic 
alternatives for addressing this issue.
    Under the first alternative EPA solicits comment on requiring 
affected EGUs to retire vintage 2015 and beyond title IV allowances at 
a rate of 2.86-to-1 rather than 3-to-1. This alternative effectively 
eliminates the difference between the proposed cap levels and the 
resulting reductions. The EPA solicits comment on the use of this 
retirement ratio and specifically on whether the use of a fractional 
retirement ratio (2.86-to-1 instead of 3-to-1) raises practical 
implementation concerns for States or affected EGUs or whether a 
fractional retirement ratio is preferable to the two-step process 
described below.
    Alternatively, EPA proposes requiring the retirement of 2015 and 
beyond vintage allowances at a 3-to-1 ratio, and permitting States to 
convert these additional reductions into allowances in their rules. 
That is, the States would retain special ``CAIR SO₂ 
allowances'' equivalent to the difference between the 3-to-1 retirement 
ratio and the effective 2015 cap. Thus, an amount of allowances 
(assuming allowances would be retired at a 3-to-1 ratio) equivalent to 
three times the number that represents the margin of difference in the 
retirement ratio for 2015 would then be made available to States. Under 
this approach, these reserved allowances would be distributed to the 
States based on the same methodology used to distribute title IV 
allowances, and States would have flexibility to further distribute 
them however they deem appropriate. The States might choose, for 
example, to distribute them to EGUs using the same methodology that had 
been used for distributing the original title IV allowances, or use 
them as a set-aside for new sources or for sources that did not receive 
title IV allowances originally, or they might distribute them as 
incentives for achieving other policy goals each State may have.
    Some States may want to use these reserved allowances to create an 
incentive for additional local emission reductions that will be needed 
to bring all areas into attainment with the PM2.5 NAAQS. The EPA 
projects that the proposed CAIR, along with other Federal and State 
programs already in place, will bring most areas of the country into 
attainment with the PM2.5 NAAQS by 2015 without the need for additional 
local controls. These regional and national programs, however, are not 
designed to deal with all local pollution problems, and we expect that 
there will be a small number of areas that will need additional local 
emissions reductions to reach attainment. In such cases, States could 
use their reserved

[[Page 32687]]

allowances to create an incentive for additional local reductions--
perhaps by providing reserved allowances to affected EGUs based on 
their proposals for achieving additional reductions in areas that are 
projected to need further local emissions reductions to come into 
attainment with the PM2.5 NAAQS.
    Mechanisms that States could use for allocating these reserved 
allowances could range from basic financial incentives to more 
aggressive and innovative approaches. In its simplest form, the EGUs 
could choose to complement or expand existing control measures, or 
perhaps fund new ones. Under the latter approach, a specific value 
could be applied to a ton of local emissions to be reduced depending on 
one or more specific criteria such as: The accuracy and technical 
validity of emissions monitoring used to characterize emissions or 
demonstrate compliance, seasonal timing or location of the reductions, 
population exposure, or other considerations.
    For example, reducing PM2.5 from a sector in a nonattainment area 
might receive a greater allowance value than reductions from a sector 
that is downwind of the nonattainment area most of the year, due to the 
relative effectiveness of the measures at reducing population exposure 
and monitoring of PM2.5. Another example could be one in which the EGUs 
receive allowances in exchange for reductions in other pollutants 
causing PM2.5, based on using technically appropriate air quality 
models to demonstrate superior environmental results. Nevertheless, 
States would have discretion on whether and how to use any reserved 
allowances to achieve additional local emission reductions.
2. Proposed SO₂ State Emission Budget Methodology
    a. Overview. In this section, EPA discusses the methodology for 
apportioning regionwide SO₂ emissions reductions 
requirements or budgets to the individual States. In the January 2004 
proposal we proposed State EGU SO₂ budgets based on each 
State's allowances under title IV of the CAA Amendments with specified 
retirement ratios. This continues to be EPA's proposal for determining 
State SO₂ budgets. In addition, we discussed an alternate 
method of relying on Title IV allowances that would provide for some 
EGU allowances that could be redistributed to account for changes to 
the electric generation sector since the title IV allocations were 
created (using a two-part budget methodology). In this SNPR, EPA 
identifies some problems with the two-part method as described in the 
January 2004 proposal, withdraws the January 2004 proposal on this 
point, and is re-proposing that all States use the same retirement 
ratios for Title IV allowances.
    b. NPR discussion. The EPA discussed its proposed SO₂ 
emission budget methodology at length in the January 2004 proposal. In 
that discussion, EPA outlined the various reasons for tying the 
SO₂ requirements of the proposed CAIR to the title IV 
program. Without carefully integrating the CAIR and title IV programs, 
emissions may increase prior to implementation of the CAIR and 
emissions may shift to outside the control region. In addition, because 
the regulated community has relied on the title IV program in the past, 
and is planning on continued reliance for the future, lack of 
integration could give rise to concerns about the stability of EPA's 
regulatory efforts and the accompanying allowance market.
    Under the approach proposed for SO₂, the State budgets 
would be based on the initial allocation of allowances to individual 
sources established by title IV of the 1990 CAA Amendments. The budgets 
are shown in Table II-1, revised to correct a slight calculation error 
in the January 2004 proposal,\3\ as explained in the technical support 
document.\4\
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    \3\ As in the SO₂ State budgets included in the 
January 2004 proposal, these budgets include the 250,000 allowances 
in the Special Allowance Reserve, prorated to the individual States 
in proportion to the sum of the 2010 individual units allocations 
for the State.
    \4\ See, ``State Emission Budget Calculation Technical Support 
Document for the Proposed Clean Air Interstate Rule (May 2004).''

  Table II-1.--28-State and District of Columbia Annual EGU SO2 Budgets
------------------------------------------------------------------------
                                           28-State SO2    28-State SO2
                  State                     Budget 2010     Budget 2015
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................         157,582         110,307
Arkansas................................          48,702          34,091
Delaware................................          22,411          15,687
District of Columbia....................             708             495
Florida.................................         253,450         177,415
Georgia.................................         213,057         149,140
Illinois................................         192,671         134,869
Indiana.................................         254,599         178,219
Iowa....................................          64,095          44,866
Kansas..................................          58,304          40,812
Kentucky................................         188,773         132,141
Louisiana...............................          59,948          41,963
Maryland................................          70,697          49,488
Massachusetts...........................          82,561          57,792
Michigan................................         178,605         125,024
Minnesota...............................          49,987          34,991
Mississippi.............................          33,763          23,634
Missouri................................         137,214          96,050
New Jersey..............................          32,392          22,674
New York................................         135,139          94,597
North Carolina..........................         137,342          96,139
Ohio....................................         333,520         233,464
Pennsylvania............................         275,990         193,193
South Carolina..........................          57,271          40,089
Tennessee...............................         137,216          96,051
Texas...................................         320,946         224,662
Virginia................................          63,478          44,435

[[Page 32688]]

West Virginia...........................         215,881         151,117
Wisconsin...............................          87,264          61,085
                                         -----------------
    Total Regional Budget...............       3,863,566      2,704,490
------------------------------------------------------------------------
 Note: As explained in the proposed January 2004 proposal (69 FR 4618)
  the regionwide budgets for the years 2010-2014 are based on a 50
  percent reduction from title IV allocations for all units in affected
  States. The regionwide budget for 2015 and beyond is based on a 65
  percent reduction.

    c. Problems with the methodology proposed in the NPR. In the Model 
Trading section of the January 2004 proposal, EPA proposed giving 
States the option of deciding whether to adopt a two-part budget 
approach, making available additional SO₂ allowances through 
the use of higher retirement ratios (69 FR 4620,4632). However, upon 
further assessment, it has become evident that problems could arise if 
various States implemented this approach differently. Specifically, the 
level of the regional cap on SO₂ emissions could increase or 
decrease, depending on which individual States tightened the retirement 
ratios.
    An example could best illustrate this point. Assume State A in the 
proposed CAIR region has a State SO₂ budget of 300,000 tons 
in 2010, reflecting a 50 percent reduction from its 600,000 2010 title 
IV SO₂ allowances. Assume also that State A decides to 
implement a 3-to-1 retirement ratio for its 600,000 title IV 
SO₂ allowances in 2010, but all other States in the proposed 
CAIR region continue requiring 2-to-1 retirement ratios. Assume further 
that EPA allocates State A additional CAIR allowances for 100,000 tons 
of emissions, which reflect the difference between State A's 3-to-1 
retirement ratio (200,000 tons) and the overall 2-to-1 retirement ratio 
(300,000 tons). With one CAIR allowance equivalent to one title IV 
allowance, State A, with its 3-to-1 ratio, would thus receive 300,000 
CAIR allowances. Assume that State A allocates all of these new CAIR 
allowances to its sources. To illustrate most vividly the problem that 
may result, assume the extreme case in which State A's emissions in 
2010 approach zero (due to efficiencies in implementing controls or 
lower generation levels) and therefore that its sources sell all their 
title IV allowances as well as its additional CAIR allowances to 
sources in other States. In this example, the total amount of State A's 
allowances (600,000 title IV allowance plus 300,000 CAIR allowances) 
would be available for complying with the 2-to-1 ratio required by the 
other States. Consequently, the additional CAIR allowances allocated by 
EPA would effectively raise the overall regional cap by 150,000 tons, 
reflecting the 300,000 CAIR allowances retired at a 2-to-1 ratio.
    To illustrate how this same case could lead to the opposite problem 
of a lower regional cap, assume that State A's emissions were to remain 
very high or to increase, so that its sources purchase allowances from 
other States and then retire them at a 3-to-1 ratio in 2010. State A 
sources would have to purchase more allowances than the amount State A 
had redistributed as additional CAIR allowances. This would mean the 
total amount of allowances for 2010, and thus the total regional cap, 
would in effect be lower.
    In fact, in these examples, in any year that State A's emissions 
are not exactly one-third of their title IV allocations, the level of 
the overall regional cap would be impacted. This lack of certainty 
about the cap is unacceptable for a cap-and-trade program, as it 
undermines both the environmental certainty and economic stability of 
the program. Therefore, EPA is withdrawing the January 2004 proposal on 
this point and re-proposing that all States use the same retirement ratio.
3. SIP Approvability
    In section III.A, EPA outlines the proposed SIP approvability 
criteria if EPA adopts a requirement to retire allowances at ratios of 
greater than 1-to-1. Specifically, (1) all States must use the same 
retirement ratios whether or not they participate in the trading 
program and whether or not they achieve all the required emissions 
reductions through controls on EGUs, (2) if a State does not require 
all of the emissions reductions through requirements on EGUs, they may 
create extra CAIR allowances which would be calculated by multiplying 
the reductions required from the other sources by the required 
retirement ratio for that given year, and (3) the overall reduction 
requirement for a State would be set at the difference between a 
State's 2010 title IV allowance allocations and the EPA-determined CAIR 
SO₂ State budgets for the two phases. Please note, as 
described in section IV, that if a State chooses to achieve emissions 
reductions from non-EGUs, then that State's EGUs may not participate in 
the EPA administered cap-and-trade program.

B. NO_X Emissions Budgets

1. Overview
    In this section, EPA discusses the apportioning of proposed 
regionwide NO_X emission reduction requirements or budgets to 
the individual States. In the January 2004 proposal we proposed State 
EGU NO_X budgets based on each State's average share of 
recent historic heat input. In today's SNPR, we propose the same heat 
input based methodology, but we propose revised budgets based on more 
complete heat input data.
    In addition to the proposed heat input based method, in this SNPR 
we also discuss a different approach suggested by commenters for 
apportioning regionwide NO_X budgets to the States. As 
discussed in section IV of this SNPR, we propose that States have the 
discretion in choosing a methodology to distribute allowances from 
their NO_X budgets to individual sources.
2. NO_X Emission Budget Methodology Proposed in the NPR
    a. NPR discussion. In the January 2004 proposal, we proposed annual 
NO_X budgets for a 28-State (and D.C.) region based on each 
jurisdiction's average heat input--using heat input data from Acid Rain 
Program units--over the years 1999 through 2002. We summed the average 
heat input from each of the applicable jurisdictions to obtain a 
regional total average annual heat input. Then, each State received a 
pro rata share of the regional NO_X emissions budget based on 
the ratio of its average annual heat input to the regional total 
average annual heat input.
    b. Today's revised proposal. In this SNPR, the use of average heat 
inputs is still our preferred approach. However, State budgets based on 
heat input data

[[Page 32689]]

from Acid Rain Program units only would not reflect the heat input of 
non-Acid Rain units. For example, a State with a large number of non-
Acid Rain units would not have the heat input from those units 
reflected in the percent of regional average annual heat input that the 
State's generation represents. Therefore, today EPA proposes to revise 
its determination of State NO_X budgets by supplementing Acid 
Rain Program unit data with annual heat input data from the U.S. Energy 
Information Administration (EIA), for the non-Acid Rain unit data. 
Table II-2 contains the proposed revised annual State NO_X 
budgets. Note that the Acid Rain Program data for 2002 has been updated 
since our analysis for the January 2004 proposal was completed and was 
included in the calculation of these budgets.

Table II-2.--28-States and District of Columbia Annual EGU NOX Budgets--
                           Based on Heat Input
------------------------------------------------------------------------
                                             State NOX       State NOX
                  State                     Budget 2010     Budget 2015
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          67,422          56,185
Arkansas................................          24,919          20,765
Delaware................................           5,089           4,241
District of Columbia....................             215             179
Florida.................................         115,503          96,253
Georgia.................................          63,575          52,979
Illinois................................          73,622          61,352
Indiana.................................         102,295          85,246
Iowa....................................          30,458          25,381
Kansas..................................          32,436          27,030
Kentucky................................          77,938          64,948
Louisiana...............................          47,339          39,449
Maryland................................          26,607          22,173
Massachusetts...........................          19,630          16,358
Michigan................................          60,212          50,177
Minnesota...............................          29,303          24,420
Mississippi.............................          21,932          18,277
Missouri................................          56,571          47,143
New Jersey..............................           9,895           8,246
New York................................          52,503          43,753
North Carolina..........................          55,763          46,469
Ohio....................................         101,704          84,753
Pennsylvania............................          84,552          70,460
South Carolina..........................          30,895          25,746
Tennessee...............................          47,739          39,783
Texas...................................         224,314         186,928
Virginia................................          31,087          25,906
West Virginia...........................          68,235          56,863
Wisconsin...............................          39,044          32,537
                                         -----------------
    Total Regional Budget...............       1,600,799       1,333,999
------------------------------------------------------------------------

    Note: NO_X control requirements for Connecticut were 
discussed in the January 2004 proposal.

    Commenters have also suggested adjusting the heat input data for 
existing units used to determine State budgets by multiplying it by 
different factors, established regionwide based on fuel type. The 
factors would reflect the inherently higher emissions rate of coal-
fired plants, and consequently the greater burden on coal plants to 
control emissions. In contrast to allocations based on historic 
emissions, the factors would also not penalize coal-fired plants that 
have already installed pollution controls. States shares would be 
determined by the amount of State heat input, as adjusted, in 
proportion to the total regional heat input. The factors could be based 
on average historic emissions rates (in lbs/mmBtu) by fuel type (coal, 
gas, and oil) for the years 1999-2002.
    The EPA also discussed in the January 2004 proposal a methodology 
used in the NO_X SIP Call (67 FR 21868) that applied State-
specific growth rates for heat input in setting State budgets. With a 
methodology similar to that used in the NO_X SIP Call, annual 
NO_X budgets would be set by using a base heat input data, 
then adjusting it by a calculated growth rate for each jurisdiction's 
annual EGU heat inputs. The EPA is not proposing to use this method for 
the CAIR because we believe that the other methods that we are 
proposing (or taking comment on) are more reasonable due to the 
inherent difficulties in predicting growth in heat input over a lengthy 
period, especially for jurisdictions that are only a part of a larger 
regional electric power dispatch region.

III. Integration With Clean Air Act Programs

    This section details how the rules that States develop to meet the 
requirements of the proposed CAIR must be structured to conform with 
CAA programs. It proposes: Specific criteria that SIPs submitted to 
meet the requirements of the proposed CAIR must meet; emissions 
inventory reporting requirements; revisions to the title IV Acid Rain 
regulations to integrate them with the proposed CAIR emissions trading 
programs; requirements to ensure that requirements of the existing 
NO_X SIP Call continue to be met; that BART-eligible EGUs in 
any State affected by CAIR may be exempted from BART if that State 
complies with the CAIR requirements through adoption of the CAIR cap-
and-trade program for SO2 and NO_X emissions. Finally, this 
section

[[Page 32690]]

provides additional discussion on the implications of the CAIR for tribes.

A. SIP Criteria

1. Introduction
    This section describes (1) the dates for submittal and 
implementation of the SIPs that we propose to require under the CAIR, 
and (2) the criteria we propose to use in determining completeness and 
approvability of such SIPs.
2. Schedule for Submission and Implementation of SIPs
    a. SIP submission schedule. In the January 2004 proposal, EPA 
proposed that States must submit the SIP revisions required under the 
CAIR as expeditiously as practicable but no later than 18 months from 
the date of promulgation of the final rule. The proposed regulatory 
text at the end of this SNPR, 40 CFR 51.123 (for NO_X 
emissions) and 40 CFR 51.124 (for SO2 emissions), contains this 
proposed submittal date.
    b. Implementation Schedule. In the January 2004 proposal, EPA 
proposed that States must implement the control measures in their CAIR 
SIP revisions by January 1, 2010. The proposed regulatory text at the 
end of this SNPR, 40 CFR 51.123 (for NO_X emissions) and 40 
CFR 51.124 (for SO₂ emissions), contains this proposed 
implementation date.
    i. Relationship to attainment dates. On April 15, 2004, the 
Administrator signed a rule to designate and classify areas under the 
8-hour ozone NAAQS. (69 FR 23858, April 30, 2004). Under the CAA, all 
areas designated as nonattainment are required to come into attainment 
with the NAAQS ``as expeditiously as practicable.'' In addition, 
specific maximum attainment dates apply to different areas depending on 
their classification. In the Eastern U.S., all 8-hour ozone areas are 
classified as subpart 1 areas, marginal areas, or moderate areas. For 
subpart 1 areas, the attainment date is no later than June 2009, 
although EPA can extend this date by up to five years based on certain 
statutory criteria. The attainment dates for marginal and moderate 
areas are June 2007 and June 2010, respectively. State implementation 
plans must achieve reductions required for attainment by the beginning 
of the complete ozone season prior to the attainment date (e.g., the 
2009 ozone season for moderate areas).
    In response to the January 2004 proposal, some commenters have 
expressed concern that the CAIR compliance dates (January 1, 2010, for 
Phase I, and January 1, 2015, for Phase 2) come too late for Eastern 
States to meet their deadlines for coming into attainment with the 8-
hour ozone NAAQS. In making ozone designations, however, EPA recognized 
that certain areas may find it difficult to adopt plans showing 
attainment by their initial attainment dates, and would choose to be 
reclassified to higher classifications with longer attainment dates. 
For example, an area reclassified to serious would have a June 2013 
attainment deadline, and would be required to achieve reductions 
required for attainment by the 2012 ozone season. It is also possible 
that some subpart 1 areas will qualify for an extension and receive an 
attainment date later than June 2009. In addition, an area failing to 
attain on time can qualify for up to two one-year extensions if it 
meets statutory criteria. Therefore, CAIR implementation by the 2013 or 
2014 ozone season could facilitate attainment by a serious area 
receiving one-year extensions.
    Some commenters also asserted that a similar timing issue arises 
for PM2.5. Assuming PM2.5 designations by the statutory deadline of 
December 2004, the PM2.5 attainment deadlines would be no later than 
early 2010, or no later than early 2015 for areas receiving a maximum 
5-year extension. To influence whether an area attains by those dates, 
reductions would have to occur one to three years earlier. Because of 
the structure of the proposed program, which creates a strong financial 
incentive for early reductions, EPA projects substantial early 
reductions in SO₂. Thus, although the Phase I cap does not 
come into place until 2010, the proposed program would achieve 
substantial reductions in SO₂ emissions. In addition, the 
same opportunity for one-year extensions mentioned for ozone exists for 
PM2.5 areas.
    In light of the discussion above, EPA requests comment on all 
aspects of the issues concerning the timing of the proposed CAIR 
compliance dates in relation to NAAQS attainment dates.
    ii. Implementation date and beginning of calendar year. The EPA 
believes that it is most straightforward for EPA to develop and 
implement the requirements of the proposed CAIR, for sources to comply 
with the proposed CAIR, and to ensure the environmental effectiveness 
of the proposed CAIR, if the compliance date for sources is the 
beginning of a calendar year (or for requirements that pertain only to 
ozone, at the beginning of the ozone season). There are several reasons 
for this approach. First, the proposed requirements for States are 
annual emissions reductions. Beginning the program at any point other 
than the start of a calendar year would require the development and 
implementation of different Federal requirements for the first year of 
the program.
    Second, different State rules to meet these requirements would also 
be necessary for the first, partial year portion of a program. States 
would have to develop partial year allocations. Additionally, States 
would have to modify monitoring and reporting requirements to address 
partial year reporting. Further, for SO₂ emissions 
reductions requirements, because of the interactions with title IV 
(which is an annual program), provisions would be needed to address 
both the annual requirements of title IV and the partial year 
requirements of the CAIR.
    For these administrative feasibility reasons, EPA proposes that the 
emissions reductions requirements begin at the start of the calendar 
year, and not at any other time during a calendar year. However, EPA 
solicits comment on the administrative feasibility issues of 
implementing these requirements on a partial year basis for the first 
year of the program.
    In particular, EPA solicits comment on the appropriate budget 
allocation method, and, to promote discussion, offers the following 
observations for both NO_X and SO₂ partial year 
budgets. For the NO_X EGU emissions budget, partial year 
allocation could be accomplished by pro-rating to account for the fact 
that the program would be implemented for less than a full year. The 
simplest method would be to pro-rate by the number of days that the 
program would be implemented. For example, if the program began on 
January 31, 2010, budgets would be pro-rated by the factor 335/365, 
where 335 equals the number of days in the year in which States will be 
required to comply with the program.
    At least in theory, more complex methodologies could be developed 
to account for the fact that the amount of generation--and therefore 
the amount of NO_X emissions--varies throughout the year 
(e.g., in many areas, summer generation is higher due to air 
conditioning load; in other areas that are heavily dependent on hydro 
power, fossil-fuel generation can vary seasonally with availability of 
hydro power). However, because factors that affect peak generation vary 
by region, EPA believes it would be very difficult to develop a 
methodology that reasonably addresses these many variations. Therefore, 
we believe that

[[Page 32691]]

the simplest pro-rata methodology described above would be appropriate 
for a partial year allocation.
    Budgets for SO₂ could be set in a similar way. A State's 
SO₂ budget could be pro-rated by the number of days that the 
program would be in place. Because of the interactions with title IV 
(an annual program), implementation of a partial year budget for 
SO₂ would be somewhat more complicated. For emissions from 
the first portion of the year in which the State was not required to 
comply with the CAIR, the Acid Rain sources would still be subject to 
the 1-to-1 retirement ratio required under title IV. For emissions from 
the second part of the year, all EGUs affected by the CAIR would be 
required to turn in allowances of that vintage year at a ratio of 2-to-1.
3. Completeness Determination
    Any SIP submittal that is made with respect to the final CAIR 
requirements first would be determined to be either incomplete or 
complete. A finding of completeness means that EPA would proceed to 
review the submittal to determine whether it is approvable. It is not a 
determination that the submittal is approvable; rather, it means the 
submittal is administratively and technically sufficient for EPA to 
determine whether it meets the statutory and regulatory requirements 
for approval. Under 40 CFR 51.123 and 40 CFR 51.124 (the proposed new 
regulations for NO_X and SO₂ SIP requirements, 
respectively), a submittal, to be complete, must meet the criteria 
described in 40 CFR, part 51, appendix V, ``Criteria for Determining 
the Completeness of Plan Submissions.'' These criteria apply generally 
to SIP submissions.
    Under CAA section 110(k)(1) and section 1.2 of appendix V, EPA must 
notify States whether a submittal meets the requirements of appendix V 
within 60 days of, but no later than 6 months after, EPA's receipt of 
the submittal. If a completeness determination is not made within 6 
months after submission, the submittal is deemed complete by operation 
of law. For rules submitted in response to the CAIR, EPA intends to 
make completeness determinations expeditiously. In addition, if a State 
fails to make any submission by the required submission date, EPA 
expects to make a finding of failure to submit within the same period 
that would apply to making a completeness determination had a SIP been 
submitted on time.
    A finding of failure to submit or incompleteness triggers the 
requirement that EPA promulgate a Federal implementation plan (FIP) 
within 2 years of the date of the finding. In addition, if a complete 
SIP is submitted in a timely fashion but EPA disapproves it, the 
requirement to promulgate a FIP within 2 years would be triggered by 
EPA's disapproval. The EPA's obligation to promulgate a FIP in either 
instance would terminate upon EPA's approval of a SIP as meeting the 
requirements of the CAIR.
4. Approvability Criteria
    a. Introduction. The approvability criteria for CAIR SIP 
submissions appear in the proposed 40 CFR 51.123 (NO_X 
emissions reductions) and in the proposed 40 CFR 51.124 (SO₂ 
emissions reductions). Most of the criteria are substantially similar 
to those that currently apply to SIP submissions under CAA section 110 
or part D (nonattainment). For example, each submission must describe 
the control measures that the State intends to employ, identify the 
enforcement methods for monitoring compliance and handling violations, 
and demonstrate that the State has legal authority to carry out its plan.
    This part of the section III preamble explains additional 
approvability criteria specific to the CAIR that were proposed in the 
January 2004 proposal, or are being proposed in today's SNPR. As 
explained in the January 2004 proposal, EPA proposed that each affected 
State must submit SIP revisions containing control measures that assure 
a specified amount of NO_X and SO₂ emissions 
reductions by specified dates.
    Although EPA determined the required amount of emissions reductions 
by identifying specified control levels for EGUs that are highly cost 
effective, EPA explained in the January 2004 proposal that States have 
flexibility in choosing the sources to control in order to achieve the 
required emissions reductions. As long as the State's emissions 
reductions requirements are met, a State may impose controls on EGUs 
only, on non-EGUs only, or on a combination of EGUs and non-EGUs. The 
EPA's proposed SIP approvability criteria are intended to provide as 
much certainty as possible that, whichever sources a State chooses to 
control, the controls will result in the required amount of emissions 
reductions.
    In the January 2004 proposal, EPA proposed a ``hybrid'' approach 
for the mechanisms used to ensure emissions reductions from sources. 
This approach incorporates elements of an emissions ``budget'' approach 
(requiring an emissions cap on affected sources) and an ``emissions 
reductions'' approach (not requiring an emissions cap). In this hybrid 
approach, if States impose control measures on EGUs, they would be 
required to impose an emissions cap on all EGUs, which would 
effectively be an emissions budget. However, as stated in the January 
2004 proposal, if States impose control measures on non-EGUs, they 
would be encouraged but not required to impose an emissions cap on non-
EGUs. In the January 2004 proposal, we requested comment on the issue 
of requiring States to impose caps on any source categories the State 
chooses to regulate.
    Today, we propose to modify this hybrid approach so that States 
choosing to impose control measures on large industrial boilers and/or 
turbines must do so by imposing an emissions cap on all such sources 
within their State. This is similar to EPA's approach in the 
NO_X SIP Call which required States to include an emissions 
cap on such sources as well as on EGUs if the SIP submittals included 
controls on such sources. (See 40 CFR 51.121(f)(2)(ii), referenced at 
63 FR 57494, October 27, 1998.)
    Below, EPA describes specific criteria, depending on which sources 
States choose to control.
b. Requirements if States Choose To Control EGUs.
    i. Emissions caps. As explained in the January 2004 proposal (69 FR 
4626), EPA proposed that States must apply the ``budget'' approach if 
they choose to control EGUs; that is, States must cap EGU emissions at 
the level that assures the appropriate amount of reductions. These caps 
constitute the State EGU budgets for SO₂ and NO_X. 
Additionally, EPA proposed that, if States choose to control EGUs, they 
must require EGUs to follow part 75 monitoring, recordkeeping, and 
reporting requirements.
    If States choose to allow their EGUs to participate in EPA-
administered interstate NO_X and SO₂ emissions 
trading programs, States must adopt EPA's model trading rules, as 
described in section IV below and as proposed in 40 CFR part 96, Sec.  
96.101-Sec.  96.176 and Sec.  96.201-Sec.  96.276, below. States 
adopting EPA's model trading rules, with only those modifications 
specifically allowed by EPA, will meet the requirements for applying an 
emissions cap as well as part 75 monitoring, recordkeeping, and 
reporting requirements to EGUs.
    If States choose to control EGUs but not to allow them to 
participate in EPA-administered NO_X and SO₂ 
emissions trading programs, States must still impose an emissions cap 
as well as part

[[Page 32692]]

75 monitoring, recordkeeping, and reporting requirements on all EGUs. 
Additionally, States must use the same definition of EGU as EPA uses in 
its model trading rules, i.e., the sources described as ``CAIR units'' 
in proposed 40 CFR 96.102 and 40 CFR 96.202. If a State chooses to 
design its own NO_X and SO₂ emissions trading 
programs, regardless of whether they are for intrastate or interstate 
trading, in addition to meeting the requirements of these rules, they 
should consider EPA's guidance, ``Improving Air Quality with Economic 
Incentive Programs,'' January 2001 (EPA-452/R-01-001) (available on 
EPA's Web site at: http://www.epa.gov/ttn/ecas/incentiv.html), and the 
rules must be approved by EPA. It should be noted that EPA would not 
administer a State-designed program, so the State (or States) would 
need to administer such programs.
    ii. Retirement Ratios. The January 2004 proposal required each 
State to assure that the title IV SO₂ allowances for vintage 
year 2010 and beyond for the State's EGUs that exceed the State's CAIR 
EGU SO₂ emissions budget cannot be used in a manner that 
would lead to emissions increases in areas not affected by the CAIR. 
Additionally, EPA was concerned that a devaluation of title IV 
allowances (because of the more stringent requirements of the CAIR) 
could lead to emissions increases prior to implementation of the CAIR. 
The EPA's concerns regarding these allowances are described in the 
January 2004 proposal at 69 FR 4630. To avoid these significant 
problems, the January 2004 proposal in effect would require the State 
to include a mechanism for retirement of the allowances in excess of 
the State's budget.
    The number of retired allowances must be at least equal to the 
difference between the number of title IV allowances allocated to EGUs 
in a State and the SO₂ budget the State sets for EGUs under 
this rule. This requirement to retire allowances in excess of a State's 
budget applies regardless of whether or not a State participates in the 
EPA-administered trading programs. If a State chooses to participate in 
the EPA-administered trading programs, the State must follow the 
provisions of the model trading rules, described in section IV below, 
that require that vintage 2010 through 2014 title IV allowances be 
retired at a ratio of 2 allowances for every ton of emissions and that 
vintage 2015 and beyond title IV allowances be retired at a ratio of 
three allowances for every ton of emissions. Pre-2010 vintage 
allowances would be retired at a ratio of one allowance for every ton 
of emissions. (See section IV.B.1 of this SNPR.)
    In the January 2004 proposal, EPA stated that if a State does not 
choose to participate in the EPA-administered trading programs, the 
State may choose the specific method to retire allowances in excess of 
its budget. The EPA has further considered alternative ways for 
retiring these excess allowances and believes that if different States 
use different means to address this concern, it could undermine the 
regionwide emission reduction goals of the proposed CAIR. The EPA's 
concerns are further described in Section II of today's preamble. 
Because of these concerns, EPA is withdrawing the January 2004 proposal 
on this point and re-proposing that all States use a 2-for-1 retirement 
ratio for vintage 2010 through 2014 allowances and a 3-for-1 retirement 
ratio for vintage 2015 allowances and beyond to address concerns about 
title IV allowances that exceed State budgets.
    State rules may also allow sources currently subject to title IV 
and to the NO_X SIP Call trading program to use allowances 
banked from those programs before 2010 for compliance with the CAIR, 
provided that States which participate in EPA's CAIR trading programs 
must allow this, in accordance with EPA's model trading rules. For 
further discussion of banking of NO_X SIP Call allowances, 
see the January 2004 proposal (69 FR 4633).
c. Requirements if States Choose to Control Sources Other Than EGUs
    i. Overview of requirements. As noted in the January 2004 proposal, 
if a State chooses to require emissions reductions from non-EGUs, the 
State must adopt and submit SIP revisions and supporting documentation 
designed to quantify the amount of reductions from the non-EGU sources 
and to assure that the controls will achieve that amount. Although EPA 
did not propose that States be required to impose an emissions cap on 
those sources but instead solicited comment on the issue, EPA proposes 
today that States be required to impose an emissions cap in certain 
cases on non-EGU sources.
    If a State chooses to obtain some but not all of its required 
emissions reductions from non-EGUs, it would still be required to set 
an EGU SO₂ budget and/or an EGU NO_X budget, but 
at some level higher than shown in Tables VI-9 and VI-10 in the January 
2004 proposal (69 FR 4619-4620), thus allowing more emissions from its 
EGUs. The difference between the amount of a State's SO₂ EGU 
budget in Table VI-9 and a State's selected higher EGU SO₂ 
budget would be the amount of SO₂ emissions reductions the 
State must demonstrate it will achieve from non-EGU sources. By the 
same token, the difference between the amount of a State's 
NO_X EGU budget in Table VI-10 and a State's selected higher 
EGU NO_X budget would be the amount of NO_X 
emissions reductions the State must demonstrate it will achieve from 
non-EGU sources.
    If States require SO₂ emissions reductions from non-EGU 
sources, States should still use the same retirement ratio (i.e., 2-
for-1 for vintage 2010 through 2014 allowances and 3-for-1 for vintage 
2015 allowances and beyond) for title IV allowances. To account for the 
fact that the State is not requiring its EGUs to reduce as much, the 
State can allocate additional allowances. The number of these 
allowances will be calculated by multiplying the emissions reductions 
required for the non-EGU source category by the title IV retirement ratio.
    The demonstration of emissions reductions from non-EGUs is a 
critical requirement of the SIP revision due from a State that chooses 
to control non-EGUs. As noted in the January 2004 proposal, the State 
must take into account the amount of emissions attributable to the 
source category in both (i) the base case, in the implementation years 
2010 and 2015, i.e., without assuming SIP-required reductions from that 
source category under the final CAIR, and (ii) in the control case, in 
the implementation years 2010 and 2015, i.e., with assuming SIP-
required reductions from that source category under the CAIR SIP. We 
are proposing an alternative methodology for calculating the base case 
for certain large non-EGU sources, as described below, but generally 
the difference between emissions in the base case and emissions in the 
control case equals the amount of emissions reductions that can be 
claimed from application of the controls on non-EGUs. (See below for 
criteria applicable to development of the baseline and projected 
control emissions inventories.)
    Additionally, if a State chooses to obtain some or all of its 
required emission reductions from non-EGUs, EGUs in that State could 
not participate in the EPA administered multi-State trading programs.
    ii. Eligibility of non-EGU reductions. In evaluating whether 
emissions reductions from non-EGUs would count towards the emissions 
reductions required under the CAIR, States may include only reductions 
attributable to measures that are not otherwise required under the CAA. 
This exclusion

[[Page 32693]]

of credit is consistent with the NO_X SIP Call. For the most 
part, the measures that are mandated by the CAA, and that EPA proposes 
be excluded from credit towards the emission reduction requirements of 
the CAIR, were assumed to be in place in the emissions projections and 
air quality contribution analysis used in the proposed findings 
regarding significant contribution to nonattainment in 2010.\5\
---------------------------------------------------------------------------

    \5\ The 2010 emissions projections did not account for 
requirements for reasonably available control technology (RACT), 
reasonably available control measures (RACM), and vehicle 
inspection/maintenance in any new 8-hour ozone or PM2.5 
nonattainment areas, as these areas had not been designated at the 
time of the modeling. However, we believe that not accounting for 
these requirements did not distort the proposed findings for each 
State because the aggregate reductions in NO_X and 
SO₂ emissions from these measures would be at most a 
small percentage of overall emissions.
---------------------------------------------------------------------------

    Specifically, States must exclude reductions attributable to 
measures otherwise required by the CAA, including: (1) Measures already 
in place at the date of promulgation of the final CAIR, such as adopted 
State rules, SIP revisions approved by EPA, and settlement agreements; 
(2) measures adopted and implemented by EPA (or other Federal agencies) 
such as emissions reductions required pursuant to the Federal Motor 
Vehicle Control Program for mobile sources (vehicles or engines) or 
mobile source fuels, or pursuant to the requirements for National 
Emissions Standards for Hazardous Air Pollutants; and (3) specific 
measures that are mandated under the CAA (which may have been further 
defined by EPA rulemaking) based on the classification of an area which 
has been designated nonattainment for a NAAQS, such as vehicle 
inspection and maintenance programs. If a State can demonstrate that a 
new or modified measure is more stringent than what is required, e.g., 
due to broader geographic coverage or more stringent emissions 
reductions levels, the State may count toward the CAIR requirement the 
reductions attributable to the more stringent requirement. The 
exclusion of credit for ineligible measures is accomplished by 
including those measures in both the base and control cases, if they 
have already been adopted; or by excluding them from both the base and 
control cases if they have not yet been adopted.
    States required to make CAIR SIP submittals may also be required to 
make other SIP submittals to meet other requirements applicable to non-
EGUs, e.g., nonattainment SIPs required for areas designated 
nonattainment under the PM2.5 or 8-hour ozone NAAQS. These SIPs could 
include, for example, measures to be adopted such as Reasonably 
Available Control Technology (RACT) measures pursuant to CAA section 182.
    It is likely that CAIR SIP submittals will be due before or at the 
same time that some of these other SIP submittals are due. States 
relying on reductions from controls on non-EGUs must commit in the CAIR 
SIP revisions to replace the emissions reductions attributable to any 
CAIR SIP measure if that measure is subsequently determined to be 
required in meeting any other SIP requirement related to adoption of 
control measures. The State could make this replacement by decreasing 
its EGU emissions cap or a non-EGU emissions cap, if applicable, by the 
appropriate amount.
    iii. Emissions controls and monitoring. As noted above, we are 
modifying the ``hybrid'' approach described in the January 2004 
proposal as it applies to non-EGUs. For States that choose to impose 
controls on certain non-EGUs, namely large industrial boilers and 
turbines, i.e., those whose maximum design heat input is greater than 
250 mmBtu/hr, to meet part or all of their emissions reductions 
requirements under the CAIR, EPA proposes that State requirements must 
include an emissions cap on all such sources in their State. 
Additionally, EPA proposes that in this situation, States must require 
those large industrial boilers and turbines to meet part 75 
requirements for monitoring and reporting emissions as well as 
recordkeeping. The EPA proposes that if a State chooses to control non-
EGUs other than large industrial boilers and turbines to obtain the 
required emissions reductions, the States must either (i) impose the 
same requirements, i.e., an emissions cap on all the non-EGUs in the 
source category and Part 75 monitoring, reporting and recordkeeping 
requirements, or (ii) must demonstrate why such requirements are not 
practicable. In the latter case, the State must adopt appropriate 
alternative requirements to ensure to the maximum practicable degree 
that the required emissions reductions will be achieved. Further, if a 
State adopts alternative requirements that do not apply to all non-EGUs 
in a particular source category (defined to include all sources where 
any aspect of production is reasonably interchangeable), the State must 
demonstrate that it has analyzed the potential for shifts in production 
from the regulated sources to lesser regulated sources in the same 
State as well as in other States, and that the State is not including 
reductions attributable to sources that may shift emissions to such 
non-regulated or not as stringently regulated sources.
    iv. Emissions inventories and demonstrating reductions. Quantifying 
emissions reductions attributable to controls on non-EGUs requires that 
the States submit both baseline and projected control emissions 
inventories for the applicable implementation years. We have issued 
many guidance documents and tools for preparing such emissions 
inventories, some of which apply to specific sectors States may choose 
to control. While much of that guidance is applicable to the proposed 
CAIR, there are some key differences between quantification of emission 
reduction requirements under a SIP designed to help achieve attainment 
with a NAAQS and emission reduction requirements under a SIP designed 
to reduce emissions that contribute to a downwind State's nonattainment 
problem. When addressing its own nonattainment problem, a State has an 
incentive not to overestimate emission reductions. If a State 
overestimates emission reductions, the potential consequence is that 
the State would remain out of attainment. Missing an attainment 
deadline has adverse impacts upon a State. Among other things, the area 
may be ``bumped up'' to a higher classification with more stringent 
requirements.
    Under transport requirements, however, overestimating emission 
reductions has fewer intrastate consequences (because it is the 
downwind State that would pay the price of remaining in nonattainment). 
For this reason, EPA believes that it is appropriate to have more 
stringent guidelines with respect to quantification of emission 
reductions under a program designed to reduce transported pollutants 
than are currently used with respect to SIPs addressing intrastate air 
pollution problems. We discuss below more stringent requirements both 
for developing baseline emission rates and for projecting future 
emission levels.
    When we review CAIR SIPs for approvability, we intend to closely 
review the emissions inventory projections for non-EGUs to evaluate 
whether the emissions reductions estimates are correct. We intend to 
review the accuracy of baseline historical emissions for the subject 
sources, assumptions regarding activity and emissions growth between 
the baseline year and 2010 and 2015, and assumptions about the 
effectiveness of control measures.
    To quantify non-EGU reductions, as the first step, a historical 
baseline must be established for emissions of SO₂ and/or 
NO_X from the non-EGU source(s) in

[[Page 32694]]

a recent year. The historical baseline inventory should represent 
actual emissions from the substitute sources prior to the application 
of the emissions controls. We expect that States will choose a 
representative year (or average of several years) falling between 2002 
and 2005, inclusively, for this purpose.
    The proposed requirements that follow for estimating the historical 
baseline inventory reflect EPA's belief that, when States assign 
emissions reductions to non-EGU sources, those reductions should have a 
high degree of certainty of actually being achieved similar to EGU 
reductions which can be quantified with a high degree of certainty in 
accordance with part 75 monitoring requirements that apply to EGUs. For 
non-EGU sources which are subject to part 75 monitoring requirements, 
historical baselines must be derived from actual emissions obtained 
from part 75 monitored data.
    For non-EGU sources that do not have part 75 monitoring data to use 
as a baseline, a historical baseline must be established that estimates 
actual emissions in a way that matches or approaches as closely as 
possible the certainty provided by the part 75 measured data for EGUs. 
In the absence of part 75 measured data, EPA proposes that States be 
required to estimate historical baseline emissions using assumptions 
that ensure a source's or source category's actual emissions are not 
overestimated; source-specific or category-specific data are required. 
Because the substitute emissions reductions are estimated by 
subtracting controlled emissions from a projected baseline, if the 
historical baseline overestimates actual emissions, the estimated 
reductions could be higher than the actual reductions achieved. As 
explained above, the use of historical baselines that do not 
overestimate emissions helps to ensure that upwind emissions reductions 
are actually achieved.
    To achieve this baseline, States must use emission factors that 
ensure that emissions are not overestimated (e.g., emission factors at 
the low end of a range when EPA guidance presents a range) or the State 
must provide additional information that shows with reasonable 
confidence that another value is more appropriate for estimating actual 
emissions. Other monitoring or stack testing data can be considered but 
care must be taken not to overestimate baselines. If a production or 
utilization factor is part of the historical baseline emissions 
calculation, again, a factor that ensures that emissions are not 
overestimated must be used, or additional data must be provided. 
Similarly, if a control-efficiency factor and/or rule-effectiveness 
factor enters into the estimate of historical baseline emissions, it 
must be realistic and supported by facts or analysis. For these 
factors, a high value (closer to 100 percent control and effectiveness) 
ensures that emissions are not overestimated.
    Once the historical baseline is established for SO₂ and/
or NO_X emissions from the substitute sources, the second 
step is to project these emissions to conditions expected in 2010 and 
2015. This step results in the 2010 and 2015 baseline emissions 
estimates. This step must be done with state-of-the-art methods for 
projecting the source's or source category's economic output. Economic 
and population forecasts must be as specific as possible to the 
applicable industry, State, and county of the source, and must be 
consistent with both national projections and relevant official 
planning assumptions including estimates of population and vehicle 
miles traveled developed through consultation between State and local 
transportation and air quality agencies. However, if these official 
planning assumptions are themselves inconsistent with official U.S. 
Census projections of population and energy consumption projections 
contained in the Annual Energy Outlook published by the U.S. Department 
of Energy, adjustments must be made to correct the inconsistency, or 
the SIP must demonstrate how the official planning assumptions are more 
accurate. Where changes in production method, materials, fuels, or 
efficiency are expected to occur between the baseline year and 2010 or 
2015, these must be accounted for in the projected 2010 and 2015 
baseline emissions. The projection must also account for any adopted 
regulations that will affect source emissions, not including the 
measures adopted for purposes of meeting the requirements of the 
proposed CAIR and eligible for that purpose. (See discussion above 
regarding eligibility of reductions from non-EGU sources.)
    The EPA is also proposing an alternative methodology for the use of 
projected 2010 and 2015 emissions. In this alternative, instead of 
using the projected 2010 and 2015 emissions as the 2010 and 2015 
baselines, States must use the lower of historical baseline emissions 
for a source category or projected 2010 or 2015 emissions, as 
applicable, for a source category. This is because, as explained above, 
changes in production method, materials, fuels, or efficiency often 
play a key role in changes in emissions. Because of factors such as 
these, emissions can often stay the same or even decrease as 
productivity within a sector increases. These factors that contribute 
to emission decreases can be very difficult to quantify. 
Underestimating the impact of these types of factors can easily result 
in a projection for increased emissions within a sector, when a correct 
estimate would result in a projection for decreased emissions within 
the sector.
    The third step is to develop the 2010 and 2015 controlled emissions 
estimates by assuming the same changes in economic output and other 
factors listed above but adding the effects of the new regulations 
adopted for the purpose of meeting the CAIR. The regulations may take 
the form of emissions caps, emission rate limits, technology 
requirements, work practice requirements, etc. The State's estimate of 
the effect of the regulations must be realistic in light of the 
specific provisions for monitoring, reporting, and enforcement and 
experience with similar regulatory approaches. The State's analysis 
must examine the possibility that these new regulations may cause 
production and emissions to shift to non-regulated or less stringently 
regulated sources in the same State or another State. If all sources of 
an industrial or other type (where any aspect of production is 
reasonably interchangeable) within the State are regulated with the 
same stringency and compliance assurance provisions, the analysis of 
production and emissions shifts need only consider the possibility of 
shifts to other States. In estimating controlled emissions in 2010 and 
2015, assumptions regarding ineligible control measures must be the 
same as in the 2010 baseline estimates. For example, if a federally 
adopted and implemented measure for the source type is assumed in one 
estimate, it must be assumed in the other.
    Thus, EPA proposes two alternative methodologies for calculating 
the 2010 and 2015 emissions reductions from non-EGUs which can be 
counted toward satisfying the CAIR. In the first alternative, the 2010 
and 2015 emissions reductions which can be counted toward satisfying 
the CAIR are the differences between (i) for 2010, the 2010 baseline 
emissions estimates and the 2010 controlled emissions estimates, and 
(ii) for 2015, the 2015 baseline emissions estimates and the 2015 
controlled emissions estimates, minus in each case any emissions that 
may shift to other sources rather than be eliminated.
    In the second alternative, the 2010 and 2015 emissions reductions 
which can be counted toward satisfying the

[[Page 32695]]

CAIR are the differences between (i) for 2010, the lower of historical 
baseline or 2010 baseline emissions estimates and the 2010 controlled 
emissions estimates, and (ii) for 2015, the lower of historical 
baseline or 2015 baseline emissions estimates and the 2015 controlled 
emissions estimates, minus in each case any emissions that may shift to 
other sources rather than be eliminated.
    v. Controls on non-EGUs only. In the January 2004 proposal, we 
stated that we believe it is unlikely States will choose to control 
only non-EGUs, but we also said we would propose in this SNPR 
provisions for determining the specified emissions reductions that must 
be obtained if States pursue this alternative. In this SNPR, EPA 
proposes that States choosing this path must ensure the amount of non-
EGU reductions is greater than or equivalent to all of the emissions 
reductions that would have been required from EGUs had the State chosen 
to assign all the emissions reductions to EGUs, for example by 
participating in EPA-administered trading programs. For SO₂ 
emissions, this amount in 2010 would be 50 percent of a State's title 
IV SO₂ allocations for all affected sources in the State 
and, for 2015, 65 percent of that amount. For NO_X emissions, 
this amount would be the difference between a State's EGU budget for 
NO_X under the CAIR and its NO_X baseline EGU 
emissions inventory as projected in the Integrated Planning Model (IPM) 
for 2010 and 2015, respectively. The proposed rule text provides tables 
of these amounts for both SO₂ and NO_X.
    In addition, EPA proposes that the same requirements described 
above (in section III.A.4.c of this preamble) regarding the eligibility 
of non-EGU reductions, emissions control and monitoring, emissions 
inventories and demonstrations of reductions, will apply to the 
situation where a State chooses to control only non-EGUs.

B. What Changes Are EPA Proposing for Emissions Reporting Requirements?

1. Purpose and Authority
    The EPA believes that it is essential that achievement of the 
emissions reductions required by the proposed CAIR be verified on a 
regular basis. Emissions reporting is the principal mechanism to verify 
these reductions and to assure the downwind affected States and EPA 
that the ozone and PM2.5 transport problems are being mitigated as 
required by the proposed CAIR. Also, EPA intends to reassess from time 
to time whether the requirements of the CAIR are effective in achieving 
the protections intended by CAA section 110(a)(2)(D)(i) for downwind 
PM2.5 and ozone nonattainment areas. To this end, EPA is proposing 
certain, limited new emissions reporting requirements for States. 
Proposed rule language for these requirements appears at the end of 
this SNPR. The rule language also would remove or simplify some current 
emissions reporting requirements which we believe are not necessary or 
appropriate, for reasons explained below.
    Because we are proposing to consolidate and harmonize the new 
emissions reporting requirements proposed today with two pre-existing 
sets of emissions reporting requirements, we review here the purpose 
and authority for emissions reporting requirements in general.
    Emissions inventories are critical for the efforts of State, local, 
and Federal agencies to attain and maintain the NAAQS that EPA has 
established for criteria pollutants such as ozone, particulate matter 
(PM), and carbon monoxide (CO). Pursuant to its authority under 
sections 110 and 172 of the CAA, EPA has long required SIPs to provide 
for the submission by States to EPA of emissions inventories containing 
information regarding the emissions of criteria pollutants and their 
precursors (e.g., volatile organic compounds (VOC)). The EPA codified 
these requirements in subpart Q of 40 CFR part 51, in 1979 and amended 
them in 1987.
    The 1990 Amendments to the CAA revised many of the provisions of 
the CAA related to the attainment of the NAAQS and the protection of 
visibility in Class I areas. These revisions established new periodic 
emissions inventory requirements applicable to certain areas that were 
designated nonattainment for certain pollutants. For example, section 
182(a)(3)(A) required States to submit an emissions inventory every 3 
years for ozone nonattainment areas beginning in 1993. Similarly, 
section 187(a)(5) required States to submit an inventory every 3 years 
for CO nonattainment areas. The EPA, however, did not immediately 
codify these statutory requirements in the CFR, but simply relied on 
the statutory language to implement them.
    In 1998, EPA promulgated the NO_X SIP Call which requires 
the affected States and the District of Columbia to submit SIP 
revisions providing for NO_X reductions to reduce their 
adverse impact on downwind ozone nonattainment areas. (63 FR 57356, 
October 27, 1998). As part of that rule, codified in 40 CFR 51.122, EPA 
established emissions reporting requirements to be included in the SIP 
revisions required under that action.
    Another set of emissions reporting requirements, termed the 
Consolidated Emissions Reporting Rule (CERR), was promulgated by EPA in 
2002, and is codified at 40 CFR part 51 subpart A. (67 FR 39602, June 
10, 2002). These requirements replaced the requirements previously 
contained in subpart Q, expanding their geographic and pollutant 
coverages while simplifying them in other ways.
    The principal statutory authority for the emissions inventory 
reporting requirements outlined in this SNPR is found in CAA section 
110(a)(2)(F), which provides that SIPs must require ``as may be 
prescribed by the Administrator * * * (ii) periodic reports on the 
nature and amounts of emissions and emissions-related data from such 
sources.'' Section 301(a) of the CAA provides authority for EPA to 
promulgate regulations under this provision.\6\
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    \6\ Other CAA provisions relevant to this SNPR include section 
172(c)(3) (provides that SIPs for nonattainment areas must include 
comprehensive, current inventory of actual emissions, including 
periodic revisions); section 182(a)(3)(A) (emissions inventories 
from ozone nonattainment areas); and section 187(a)(5) (emissions 
inventories from CO nonattainment areas).
---------------------------------------------------------------------------

2. Existing Emission Reporting Requirements
    As noted above, at present, two sections of title 40 of the CFR 
contain emissions reporting requirements applicable to States: Subpart 
A of part 51 (the CERR) and section 51.122 in subpart G of part 51 (the 
NO_X SIP Call reporting requirements). This SNPR would 
consolidate these, with modifications as proposed below. The 
modifications are intended to achieve the additional reporting needed 
to verify the reductions required by the proposed CAIR, to harmonize 
the emissions reporting requirements, to reduce and simplify them, and 
to make them more easily understood.
    Under the NO_X SIP Call requirements in section 51.122, 
emissions of NO_X for a defined 5-month ozone season (May 1 
through September 30) from sources that the State has subjected to 
emissions control to comply with the requirements of the NO_X 
SIP Call are required to be reported by the affected States to EPA 
every year. However, emissions of sources reporting directly to EPA as 
part of the NO_X trading program are not required to be 
reported by the State to EPA every year. The affected States are also 
required to report ozone season emissions and typical summer daily 
emissions of NO_X from all sources every

[[Page 32696]]

third year (2002, 2005, etc.) and in 2007. This triennial reporting 
process does not have an exemption for sources participating in the 
emissions trading programs. Section 51.122 also requires that a number 
of data elements be reported in addition to ozone season NO_X 
emissions. These data elements describe certain of the source's 
physical and operational parameters.
    Emissions reporting under the NO_X SIP Call as first 
promulgated was required starting for the emissions reporting year 
2002, the year prior to the start of the required emissions reductions. 
The reports are due to EPA on December 31 of the calendar year 
following the inventory year. For example, emissions from all sources 
and types in the 2002 ozone season were required to be reported on 
December 31, 2003. However, because the Court which heard challenges to 
the NO_X SIP Call delayed the implementation by 1 year to 
2004, no State was required to start reporting until the 2003 inventory 
year. In addition, EPA recently promulgated a rule to subject Georgia 
and Missouri to the NO_X SIP Call with an implementation date 
of 2007. (See 69 FR 21604, April 21, 2004.) For them, emissions 
reporting begins with 2006. These emissions reporting requirements 
under the NO_X SIP Call affect the District of Columbia and 
22 of the 29 States affected by the proposed CAIR.
    As noted above, the other set of emissions reporting requirements 
is codified at subpart A of part 51. Although entitled the CERR, this 
rule left in place the separate Sec.  51.122 for the NO_X SIP 
Call reporting. The CERR requirements were aimed at obtaining emissions 
information to support a broader set of purposes under the CAA than 
were the reporting requirements under the NO_X SIP Call. The 
CERR requirements apply to all States.
    Like the requirements under the NO_X SIP Call, the CERR 
requires reporting of all sources at 3-year intervals (2002, 2005, 
etc.). It requires reporting of certain large sources every year. 
However, the required reporting date under the CERR is 5 months later 
than under the NO_X SIP Call reporting requirements. Also, 
emissions must be reported for the whole year, for a typical day in 
winter, and a typical day in summer, but not for the 5-month ozone 
season as is required by the NO_X SIP Call. Finally, the CERR 
and the NO_X SIP Call differ in what non-emissions data 
elements must be reported.
3. Proposed Emissions Reporting Requirements
    The EPA proposes to further consolidate the detailed requirements 
for emissions reporting by States entirely into subpart A, while adding 
limited new requirements for emissions reports to serve the additional 
purposes of verifying the CAIR-required emissions reductions. This will 
allow EPA to monitor compliance with the CAIR, as well as assess from 
time to time progress in mitigating the interstate transport of ozone 
and PM_2.5 precursors.
    This SNPR would also harmonize the reporting requirements, and 
reduce and simplify them in several ways. The major changes included in 
the proposed rule text are described below. A technical support 
document in the docket provides a detailed explanation of every change 
and its purpose.\7\
---------------------------------------------------------------------------

    \7\ ``Technical Support Document on Emissions Inventory 
Reporting Requirements for the Proposed Clean Air Interstate Rule 
(May 2004)'' can be obtained from the docket for today's proposed 
rule: OAR-2003-0053.
---------------------------------------------------------------------------

    Amendments are proposed to subpart A, which contains Sec.  51.1 
through 51.45 and an appendix, and to Sec.  51.122 in particular. We 
also propose to add a new Sec.  51.125.
    ? In Sec.  51.122, we propose to abolish certain 
requirements entirely, and to replace certain requirements with a cross 
reference to subpart A so that detailed lists of required data elements 
appear only in subpart A. As amended, Sec.  51.122 will specify what 
pollutants, sources, and time periods the States subject to the 
NO_X SIP Call must report and when, but will no longer list 
the detailed data elements required for those reports.
    ? The new Sec.  51.125 will be functionally parallel to 
Sec.  51.122, specifying what pollutants, sources, and time periods the 
States subject to the proposed CAIR must report and when, referencing 
subpart A for the detailed data elements required.
    ? The amended subpart A will list the detailed data elements 
as well as provide information on submittal procedures, definitions, 
and other generally applicable provisions.
    Taken together, the existing emissions reporting requirements under 
the NO_X SIP Call and CERR are already rather comprehensive 
in terms of the States covered and the information required. Therefore, 
the practical impact of the changes proposed today is to impose only 
three new requirements.
    First, in Arkansas, Iowa, Louisiana, Mississippi, and Wisconsin, 
for which we have proposed a finding of significant contribution to 
ozone nonattainment in another State but which were not among the 22 
States subject to the NO_X SIP Call, the required emissions 
reporting will be expanded to match those of the 22 States. The change 
requires that they report NO_X emissions during the 5-month 
ozone season, in addition to the existing requirement for reporting 
emissions for the full year. We are proposing that this new requirement 
begin with the triennial inventory year prior to the CAIR 
implementation date. This will be the 2008 inventory year, the report 
for which will be due to EPA by June 1, 2010.
    Second, under the existing CERR, yearly reporting is required only 
for sources whose emissions exceed specified amounts. Under this SNPR, 
the 28 States and the District of Columbia subject to the CAIR for 
reasons of PM_2.5 must report to EPA each year a set of 
specified data elements for all sources subject to new controls adopted 
specifically to meet the CAIR requirements related to PM_2.5, 
unless the sources participate in an EPA-administered emissions trading 
program. This is like the every-year reporting requirement for 
controlled sources under the NO_X SIP Call, but covering SO2 
in addition to NO_X and covering the whole year--since the 
PM_2.5 NAAQS at issue is the annual NAAQS--rather than only 
the ozone season. This proposal could increase the number of sources 
for which States must submit reports each year rather than only every 
third year, if a State chooses to control non-EGU sources under this 
SNPR or if the State does not join the EPA trading programs for EGUs. 
We are proposing that this new requirement begin with the 2009 
inventory year, the report for which will be due to EPA by June 1, 
2011. After the 2009 reporting year, this new requirement will have no 
effect on States that fully comply with the CAIR by requiring their 
EGUs to participate in the EPA model cap-and-trade programs.
    Third, in all States, we are proposing to expand the definition of 
what sources must report in point source format, so that fewer sources 
would be included in non-point source emissions.\8\ We are proposing to 
base the requirement for point source format reporting on whether the 
source is a major source under 40 CFR part 70 for the pollutants

[[Page 32697]]

for which reporting is required, i.e., for CO, VOC, NO_X, 
SO₂, PM_2.5, PM₁₀ and ammonia but 
without regard to emissions of hazardous air pollutants. Currently, the 
requirement for point source reporting is based on actual emissions in 
the year of the inventory report. This change may require more sources 
than at present to be reported as point sources every third year. The 
new approach will make it possible to better track source emissions 
changes, shutdowns, and start ups over time. It will result in a more 
stable universe of reporting point sources, which in turn will 
facilitate elimination of overlaps and gaps in estimating point source, 
as compared to non-point source, emissions. Under this proposal, States 
will know well in advance of the start of the inventory year which 
sources will need to be reported. We are proposing that these new 
requirements begin with the 2008 inventory year, the report for which 
will be due to EPA by June 1, 2010. We invite comment on whether this 
change could instead be practically implemented for the 2005 inventory 
year, which we believe is desirable if it is practicable. We intend to 
finalize this proposed change even if for some reason the new emissions 
reductions requirements of the proposed CAIR and the above two changes 
in emission reporting requirements are not finalized as proposed, 
because this change is appropriate for the purposes of monitoring the 
effectiveness of current SIP programs.
---------------------------------------------------------------------------

    \8\ We use the term ``non-point source'' to refer to a 
stationary source that is treated for inventory purposes as part of 
an aggregated source category rather than as individual facility. In 
the existing subpart A of part 51, such emissions sources are 
referred to as ``area sources.'' However, the term ``area source'' 
is used in section 112 of the CAA to indicate a non-major source of 
hazardous air pollutants, which could be a point source. As 
emissions inventory activities increasingly encompass both NAAQS-
related pollutants and hazardous air pollutants, the differing uses 
of ``area source'' can cause confusion. Accordingly, EPA proposes to 
substitute the term ``non-point source'' for the term ``area 
source'' in subpart A, Sec.  51.122, and the new Sec.  51.125 to 
avoid confusion.
---------------------------------------------------------------------------

    A number of proposed changes will reduce reporting requirements on 
States or provide them with additional options:
    ? The NO_X SIP Call rule required the affected 
States to submit emissions inventory reports for a given ozone season 
to EPA by December 31 of the following year. The CERR requires similar 
but not identical reports from all States by the following June 1, 5 
months later. The EPA believes that harmonizing these dates would be 
efficient for both States and EPA. We are proposing to move the 
December 31 reporting requirement to the following June 1, the more 
generally applicable submission date affecting all 50 States. We invite 
comment on whether allowing this 5-month delay is consistent with the 
air quality goals served by the emissions reporting requirements. 
However, we also invite comment on the alternative of moving forward to 
December 31 all or part of the June 1 reporting for all 50 States. In 
particular, we solicit comment on requiring that point sources be 
reported on December 31 and other sources on June 1. This approach 
would eliminate the problem of States having to make two submissions 
for point sources within a 5-month period, and would result in more 
timely submission of the emissions information for point sources. More 
timely submission would be particularly useful for point sources 
because point sources generally are the primary subject of control 
measures in SIPs. The later June 1 submission date for non-point 
sources and mobile sources would allow more time for estimating these 
emissions sources, which in some cases may require vehicle miles 
traveled or business activity data not available in time for a December 
31 submission. In addition, estimating emissions of some types of non-
point sources requires prior knowledge of emissions and activity levels 
at point sources of the same industrial type; therefore, it makes sense 
to stagger the submission deadlines for those different sources.
    ? We also propose to eliminate a requirement of the 
NO_X SIP Call for a special all-sources report by affected 
States for the year 2007, due December 31, 2008. The normal cycle of 
every-third-year reporting would also produce the same type of all-
sources reports for 2005 and 2008. The EPA originally intended to use 
the information on 2007 emissions to re-assess the effectiveness of the 
NO_X SIP Call in eliminating upwind NO_X emissions 
that contribute significantly to downwind ozone nonattainment as of the 
latest 1-hour ozone attainment date within the region. The large 
majority of the emissions reductions required by the NO_X SIP 
Call have been assigned to sources that participate in the EPA-
administered trading program, which has independent procedures to 
ensure that emissions reductions are achieved. We now believe that 
examining 2005 and 2008 inventory submissions and the annual reporting 
on controlled sources will permit us to evaluate the effectiveness of 
individual State rules or implementation practices in reducing 
emissions. We no longer need the special 2007 emissions inventory 
information to broadly revisit the NO_X SIP Call, and we 
recognize that preparing that inventory could draw resources away from 
more important work by State air agencies.
    ? We propose to remove a requirement in the existing CERR 
for reporting annual and typical ozone season day biogenic emissions. 
Because biogenic emissions vary greatly with daily weather conditions 
and because there are other practical methods for obtaining hourly 
estimates across whole regions when needed by EPA, States, or others, 
we believe this requirement for reporting biogenic emissions serves no 
useful purpose. This change does not affect our expectation that 
biogenic emissions be appropriately considered in ozone and 
PM_2.5 attainment demonstrations.
    ? We are proposing a new provision which would allow States 
the option of providing emissions inventory estimation model inputs in 
lieu of actual emissions estimates, for source categories for which 
prior to the submission deadline EPA develops or adopts suitable 
emissions inventory estimation models and by guidance defines their 
necessary inputs. This provision will allow source reporting to evolve 
to take advantage of new emissions estimation tools for greater 
efficiency, although the States will remain required to provide inputs 
representative of their conditions. We propose this option be available 
starting with the reports on 2003 emissions.
    ? We are proposing to delete the existing requirement that 
all States report emissions for a winter work weekday. This requirement 
was originally aimed at tracking progress towards attainment of the CO 
NAAQS. We believe applying this requirement to all States is no longer 
warranted given that CO violations are currently observed in few areas. 
We believe we can work directly with the remaining affected States to 
monitor efforts to attain, without requiring formal submission of CO 
inventories.
    The NO_X SIP Call rule and the CERR contain detailed 
lists of required data elements in addition to emissions, and each rule 
has its own set of definitions. The two sets of data elements overlap 
but are not identical. Generally, the NO_X SIP Call rule 
required more data elements to be reported. The EPA has reviewed both 
lists in light of more recent experiences and insight into the 
difficulty States face in collecting and submitting these data elements 
and their utility to EPA, other States, and other users. We are 
proposing to combine the separate lists of required elements into a 
single new list of required data elements. A few data elements are 
proposed to be eliminated, as explained in the technical support 
document for inventory reporting. We propose that these relatively 
minor changes become applicable starting with the first required 
emissions reports following the promulgation of the final CAIR, which 
we expect to be the reports regarding emissions during 2003, due June 
1, 2005.
    There are a number of currently required data elements that have 
been kept in the proposed rule text, but on which we invite comment as 
to whether

[[Page 32698]]

they should be dropped in the final rule. These are heat content 
(fuel), ash content (fuel), sulfur content (fuel) for fuels other than 
coal, activity/throughput, hours per day in operation, days per week in 
operation, weeks per year in operation, and start time in the day. 
These data elements have been carried forward from emissions reporting 
systems dating back many years. We believe it is appropriate to take 
comment on their current usefulness.
    We also invite comment on whether the current data elements that 
describe emissions control equipment type and efficiency are adequate. 
We believe it is important for States to report on the manner in which 
sources are currently controlled so that opportunities for additional 
highly cost-effective controls can be assessed from time to time, but 
the existing data elements may not be adequate and appropriate for that 
purpose. The present data elements related to control measures are 
primary control efficiency, secondary control efficiency, control 
device type, and rule effectiveness for point sources; and total 
capture/control efficiency, rule effectiveness, and rule penetration 
for non-point sources and nonroad mobile sources.\9\
---------------------------------------------------------------------------

    \9\ Additional information on emissions data elements and the 
formats and valid codes presently in use for State reporting to EPA 
is available on the EPA Web site 
http://www.epa.gov/ttn/chief/nif/index.html.

---------------------------------------------------------------------------

    We are proposing to retain the requirement for reporting of summer 
day emissions from all sources (except biogenic sources) at 3-year 
intervals, but to restrict it to only States with ozone nonattainment 
areas or for which we are proposing a finding of significant 
contribution to ozone nonattainment in another State. The 
NO_X SIP Call requires reporting only of NO_X 
emissions for a typical summer day, while the CERR requires reporting 
of all pollutants. We propose to restrict the requirement to VOC and 
NO_X emissions, but we invite comment on whether CO emissions 
should be required also.
    At present, States are required to report three particular data 
elements for point source stacks: Stack diameter, exit gas velocity, 
and exit gas flow rate. This is a redundant requirement, since any one 
of these can be calculated from the other two. We invite comment on 
which of these to drop from the required list of data elements, if any. 
Our preference would be to collect the data element that is most 
closely tied to an actual operating measurement. Alternatively, we may 
allow States to report either exit gas flow or exit gas velocity, at 
their option.
    Finally, we propose to modify section 51.35 of subpart A, to 
provide that if States obtain one-third of their necessary emissions 
estimates from point sources and/or prepare one-third of their non-
point or mobile source emissions estimates each year on a rolling 
basis, they should submit their data as a single package on the 
required every-third-year submission date.

C. Acid Rain Program

    In this SNPR, EPA proposes several revisions of the Acid Rain 
Program regulations (40 CFR parts 72 through 78). Most of the proposed 
revisions would affect the provisions in the regulations concerning the 
requirement to hold allowances sufficient to authorize annual 
SO₂ emissions. These proposed revisions would facilitate the 
interaction of the Acid Rain Program with the proposed CAIR trading 
program. However, because these proposed modifications also would 
benefit the implementation of the existing Acid Rain Program, EPA is 
proposing to adopt them regardless of whether other rules proposed in 
the CAIR are adopted.
    As the basis for these proposed revisions of the Acid Rain Program 
regulations, EPA proposes to modify its interpretation of title IV of 
the CAA and, specifically, provisions in sections 403, 404, 405, 408, 
409, 411, and 414, concerning the requirement to hold allowances. 
Provisions in each of these sections address the allowance-holding 
requirement by: Stating the requirement that sufficient allowances be 
held for a unit after a calendar year to authorize emissions at least 
equal to the unit's tonnage of SO₂ emissions during that 
year; referencing this requirement; or establishing the penalties and 
offsets for violation of this requirement.
    The following is a description of these statutory provisions. 
Section 403(g) is a general prohibition barring each affected unit from 
emitting SO₂ in excess of the number of allowances ``held 
for that unit for that year by the owner or operator of the unit'' (42 
U.S.C. 7651b(g)). Various provisions in sections 404 and 405 refer to 
existing units (those commencing commercial operation before November 
15, 1990) and state that a unit's emissions may not exceed its 
allowance allocation unless the owner or operator of such unit ``holds 
allowances to emit not less than the unit's total annual emissions'' 
(42 U.S.C. 7651c(a), 7651c(c)(2), 7651c(d)(1) and (5), 7651d(b)(1) and 
(3), 7651d(c)(1) through (3) and (5), 7651d(d)(1) and (2), 7651d(e), 
7651d(f)(1), 7651d(h)(1)).\10\ Section 403(e) refers to new units and 
States that it is unlawful for such a unit ``to emit an annual tonnage 
of sulfur dioxide in excess of the number of allowances to emit held 
for the unit by the unit's owner or operator'' (42 U.S.C. 
7651b(e)).\11\ Section 403(d)(1) provides that ``the total tonnage of 
emissions in any calendar year (calculated at the end thereof) from all 
units in such a utility system, power pool, or allowance pool 
agreements shall not exceed the total allowances for such units for the 
calendar year concerned'' (42 U.S.C. 7651b(d)(2)). Section 403(f) 
states that each permit under titles IV and V of the CAA must provide 
that ``the affected unit may not emit an annual tonnage of sulfur 
dioxide in excess of the allowances held for that unit'' (42 U.S.C. 
7651b(f)).\12\ Section 411(a) establishes the owner or operator's 
liability for an excess emissions penalty if SO₂ is emitted 
at the unit in excess of the ``allowances the owner or operator holds 
for use for the unit for that calendar year'' (42 U.S.C. 7651j(a)).\13\ 
Finally, section 414 provides that the operation of an affected unit to 
emit SO₂ in excess of ``allowances held for such unit'' is a 
violation of the CAA, with each ton emitted in excess of allowances 
held constituting a separate violation (42 U.S.C. 7651m).
---------------------------------------------------------------------------

    \10\ See also 42 U.S.C. 7651h(f) (section 409(f), referring to 
repowered sources and the ``prohibition against emitting sulfur 
dioxide in excess of allowances held'').
    \11\ See also 42 U.S.C. 7651d(g)(1) (section 405(g)(1), 
referring to certain new units and stating that a unit's emissions 
may not exceed its allowance allocation unless the owner or operator 
of such unit ``holds allowances to emit not less than the unit's 
total annual emissions'').
    \12\ See also 42 U.S.C. 7651g(a) (section 408(a)(1), stating 
that each permit must prohibit ``annual emissions of sulfur dioxide 
in excess of the number of allowance to emit sulfur dioxide the 
owner or operator, or the designated representative of the owners or 
operators, of the unit hold for the unit''); and 42 U.S.C. 
7651g(d)(4) (section 408(d)(4), stating that each Phase II permit 
must bar ``affected units at the affected source'' from emitting 
``in excess of the number of allowances to emit sulfur dioxide the 
owner or operator or designated representative hold for the unit'').
    \13\ See also 42 U.S.C. 7651j(b) (section 411(b), stating that 
the owner or operator of ``any affected source that emits sulfur 
dioxide during any calendar year in excess of * * * the allowances 
held for the unit for the calendar year'' is liable for an equal 
tonnage offset of the excess emissions).
---------------------------------------------------------------------------

    In summary, sections 403(e) through (g), 408(a) and (d), 411(a) and 
(b), and 414 all state that the owner or operator must hold allowances 
``for the unit'' at least equal to the unit's SO₂ emissions. 
While section 403(d)(2) refers to ``all units'' on a ``utility system's 
power pool, or allowance pool agreements,'' EPA interprets this 
provision as consistent with the requirement that

[[Page 32699]]

allowances must be held for each such unit at least equaling the unit's 
emissions.\14\ The remaining provisions cited above contain a more 
shorthand reference to the allowance-holding requirement by simply 
stating that the owner or operator must hold sufficient allowances for 
a unit's emissions.
---------------------------------------------------------------------------

    \14\ See 64 FR 25835-25837 (explaining that the legislative 
history of section 403(d)(2) indicates that the provision was not 
intended to require or authorize aggregation of such units' 
allowances to determine compliance with the allowance-holding 
requirement).
---------------------------------------------------------------------------

    Moreover, section 403(b) of the CAA requires the Administrator to 
establish by regulation the allowance tracking system, including the 
requirements for ``allocation, transfer, and use of allowances'' (e.g., 
for the holding of allowances). 42 U.S.C. 7651b(b). For example, in 
establishing the allowance tracking system, the regulations must 
specify which accounts in the allowance tracking system must contain 
allowances used to meet the allowance-holding requirement. However, 
none of the above-described statutory provisions on the allowance-
holding requirement specifically identify the type of account in which 
a unit's owner or operator must hold allowances in order to meet that 
requirement. In particular, these statutory provisions do not state, 
and thus are ambiguous concerning, whether the account must be an 
account unique to the unit ``for'' which allowances are held (i.e., a 
unit-level account) or whether the account can be ``for'' all units at 
a given source (i.e., a source-level account).
    The EPA has exercised its authority under section 403(b) in several 
prior rulemakings, in which EPA considered the question of what type of 
account could be used to hold allowances ``for'' a unit to meet the 
allowance-holding requirement. In the initial rulemaking for the Acid 
Rain Program that resulted in the January 11, 1993 core rules for the 
program, EPA interpreted the statutory provisions on allowance holding 
to mean that, in general, allowances ``for'' a unit could be held only 
in an account unique to that unit (referred to in the regulations as a 
``unit account''). (See 63 FR 41358, 41362, August 3, 1998) (discussing 
that allowances had to be held in a subaccount (the ``compliance 
subaccount'') of the unit account). Even so, the January 11, 1993 rules 
include an exception, continued in the existing rules, for affected 
units that share a common stack and monitor at the stack, not at the 
individual units. For such common-stack units, the designated 
representative has the option to assign (before the allowance transfer 
deadline) a percentage of allowances to be deducted from the unit 
account for each unit so that the total deduction for all the common-
stack units equals the total annual emissions from these units. If the 
option is not exercised, an equal percentage of the allowances is 
deducted from the unit account of each unit. The assigned, or the 
default, deductions need not have any relationship to the actual 
distribution of emissions among the common-stack units. Consequently, 
the treatment of common-stack units effectively allows the allowances 
in a unit's unit account to be used to cover emissions from another 
unit at the same source. (See 63 FR 41362.)
    In a rulemaking completed in May 1999, EPA reconsidered and revised 
its interpretation of title IV, and revised the Acid Rain Program 
regulations, in order to allow a unit to use some allowances in the 
unit account of another unit at the source to meet the allowance-
holding requirement. (64 FR 25834, May 13, 1999). This revision applied 
to units at the same source even if they were not common-stack units. 
The revised regulations resulting from that rulemaking allow a unit to 
use allowances in the unit account of another unit at the same source 
up to a limit equal to the greater of: 95 percent of the difference 
between the first unit's emissions and the allowances in its own unit 
account; or 10 tons. See 40 CFR 73.35(b)(3) (Sec.  73.35(b)(3)). This 
approach effectively allows the owner or operator to approach source-
wide compliance in that, except for the above-described limit, 
allowances at one unit are considered to be held ``for'' another unit 
at the same source and can be used to meet the allowance-holding 
requirement. The EPA explained that the limit on using another unit's 
allowances would ``provide owners and operators with a strong incentive 
to hold sufficient allowances in an affected unit's account'' and that 
compliance would ``routinely'' be achieved on a unit-by-unit basis. (64 
FR 25837). In adopting this interpretation of the ambiguous language in 
title IV concerning the allowance-holding requirement, EPA stated that 
it was balancing the general unit-by-unit orientation of title IV and 
the need for ``compliance flexibility.'' Compliance flexibility is 
necessary to reduce excess emission penalties where there are 
insufficient allowances in the unit's unit account due to 
``inadvertent, minor errors'' but enough allowances in the account of 
another unit at the same source.
    In today's SNPR, EPA is reconsidering the extent to which 
allowances in the account of one unit at a source can be used to meet 
the allowance-holding requirement for another unit at the same source. 
There are several factors relevant to this reconsideration. The first 
factor is that, as discussed above, the statutory provisions setting 
forth the allowance-holding requirement do not specifically refer to 
allowance accounts, much less dictate the type of account in which 
allowances must be held ``for the unit'' in meeting this requirement. 
To the extent only allowances held in a unit-level account are treated 
as being held ``for'' the unit involved, compliance must be met on an 
individual-unit basis. To the extent all allowances held in a source-
level account are treated as being held ``for'' all units at the source 
involved, compliance may be met on a source-wide basis. In light of the 
ambiguity in the statutory allowance-holding-requirement provisions, 
EPA believes that it has discretion in determining whether to apply the 
allowance-holding requirement at the unit level or the source level. 
Indeed, EPA maintains that the degree of compliance flexibility that 
was provided in the May 13, 1999 rulemaking did not exhaust EPA's 
discretion in moving toward source-level compliance.
    The second factor considered by EPA is that it is important to 
provide compliance flexibility by allowing one unit at a source to use, 
for compliance, allowances from other units at that source. The 
statutory excess emissions penalty of $2,000 (adjusted for inflation 
since 1990 to about $2,900) per ton is over ten times the current 
market value of an allowance. Moreover, unlike the general civil 
penalties under section 113 for violations of the CAA, section 411 
makes the excess emission penalty automatic (not discretionary) and 
therefore applicable to all excess emissions at a unit, even if they 
result from inadvertent, minor errors by the owner or operator. 
Consequently, companies have potential liability for large excess 
emissions penalty payments for what may be inadvertent, minor errors. 
For example, a company may have acquired enough allowances to authorize 
all the annual emissions from units at a source but incorrectly 
distributed the allowances among the unit accounts for those units. The 
distribution may be incorrect because of something as simple as: An 
error by the owner or operator in calculating how many allowances will 
remain in each unit account after allowance transfers submitted just 
before the allowance transfer deadline are recorded; an error in the 
allowance amount, or in the account number of the transferee, listed

[[Page 32700]]

in an allowance transfer form; or an error in identifying the unit for 
which collected emission data are reported.
    In the May 13, 1999 rulemaking, EPA partially addressed this 
problem by allowing a unit with fewer allowances in its unit account 
than emissions to use allowances in the unit accounts of other units at 
the source, but with a limit on that use. (See 63 FR 41360 and 64 FR 
25838-25839). Under the current Sec.  73.35(b)(3), the unit may use 
allowances from other units at the source to eliminate up to the 
greater of: 95 percent of that unit's allowance deficit; or 10 tons. 
While this can significantly reduce a unit's potential liability for 
excess emission penalty payments, the excess emission penalty payments 
can still be quite large, particularly when the allowance deficit is 
large enough that the 95 percent limit, rather then the 10-ton limit, 
applies. The 95 percent limit applies whenever the allowance deficit 
exceeds 200. An error, such as reversing digits in the allowance amount 
in a transfer form or misidentifying the unit for which collected 
emission data are reported, can easily result in a very large allowance 
deficit and therefore in a large penalty payment when the 95 percent 
limit on use of other units' allowances applies. In short, the current 
provisions in Sec.  73.35(b)(3) do not fully (and in EPA's view do not 
sufficiently) address the problem of excess emission penalty payments 
that potentially are far out of proportion to the errors involved.
    The third factor considered by EPA is that, as noted in prior 
rulemakings, title IV evidences in language addressing matters beyond 
the allowance-holding requirement a ``pervasive unit-by-unit 
orientation.'' (See 63 FR 41360). For example, the applicability of 
title IV is determined on a unit-by-unit basis under sections 402 
(definitions of ``unit,'' ``existing unit,'' ``new unit,'' ``utility 
unit,'' and ``affected unit''), 403(e), 404(a)(1), and 405. Allowances 
are allocated, and annual SO₂ emission limitations are set, 
for individual units. Under section 411(a), excess emissions penalties 
are imposed on owners and operators of units that have excess 
emissions, while, under section 411(b), offsets of excess emissions are 
imposed on owners and operators of sources with units that have excess 
emissions. Section 412(a) requires unit-by-unit monitoring of 
emissions, except that, in the case of units at a common stack, 
separate monitors for each unit are not required if sufficient 
information for compliance determinations is provided.
    Balancing the three above-described factors, EPA proposes to revise 
the Acid Rain regulations to allow a unit to use for compliance any 
allowances from other units at the same source.\15\ This approach 
limits the extent of deviation from the unit-by-unit orientation 
evidenced in the non-allowance-holding provisions of title IV in that a 
unit may only use allowances held for other units that are at 
essentially the same geographic location as that unit, i.e., other 
units that are at the same source. Moreover, there are no significant 
environmental consequences to shifting from unit- to source-level 
compliance. This approach is also feasible in that it does not require 
any dramatic changes in the operation of the Acid Rain Program. For 
example, only one designated representative (i.e., the designated 
representative of the source at which the units are located) will be 
involved in ensuring that there are sufficient allowances to cover 
emissions as of the allowance transfer deadline. It also appears that 
this approach will result in a minimum of changes to existing contracts 
involving allowance agreements among different owners of units at a 
source. This is because Sec.  73.35(b)(2) already allows a unit to use 
allowances from other units at the same source within certain limits 
(i.e., the 95 percent and 10 ton limits described above), and today's 
SNPR simply removes those limits.
---------------------------------------------------------------------------

    \15\ For the reasons set forth in the preamble of the May 13, 
1999 final rule, EPA maintains that allowing company-level 
compliance or compliance at any other, higher level is neither 
required by title IV nor appropriate. See 64 FR 25835-25837.
---------------------------------------------------------------------------

    In order to implement the proposal to allow a unit to use 
allowances from other units at the same source without limit, EPA is 
proposing the following specific changes to the Acid Rain Program 
regulations. The EPA's objective is to implement the proposal, but with 
a minimum of changes to the language of the Acid Rain Program 
regulations. Other than implementing the proposed shift from unit- to 
source-level compliance, these proposed revisions are not intended to 
make any substantive changes to the revised provisions.
    1. The term ``unit account'' is replaced by ``compliance account'' 
in Sec.  72.2 and, as appropriate, in every other provision of the Acid 
Rain Program regulations in which the term appears. Similarly, 
references to a ``unit's'' account in the Allowance Tracking System are 
replaced by references to a ``source's'' account. In addition, 
references to allowances held by a ``unit'' are changed to refer to 
allowances held by a ``source.''
    2. References to a ``unit's'' Acid Rain emissions limitation for 
SO₂ are replaced by references to a ``source's'' Acid Rain 
emissions limitation for SO₂ throughout the Acid Rain 
Program regulations. Similarly, references to a ``unit's'' 
SO₂ emissions for purposes of applying the SO₂ 
emissions limitation (or a ``unit's'' excess emissions) are replaced, 
where appropriate, by references to the SO₂ emissions of the 
``affected units at a source'' or to a ``source's'' excess emissions. 
It should be noted that the proposed rule language accompanying this 
preamble attempts to list every instance in which the terms ``unit's'' 
Acid Rain emissions limitation for SO₂ and ``unit's'' 
SO₂ emissions or excess emissions (as well as the terms 
``unit account,'' a ``unit's'' account, and allowances held by a 
``unit'') appear and should be replaced. However, even if some 
instances were missed, EPA proposes to replace the term in all 
instances necessary to implement source-level compliance with the 
allowance-holding requirement and requests comment on, among other 
things, what other instances may have been missed.
    3. The provisions in Sec. Sec.  72.90(b)(5) and 73.35(e) concerning 
the assignment of allowance deductions among units at a common stack 
are removed. These provisions are unnecessary with the shift from unit- 
to source-level compliance.
    4. The terms ``compliance subaccount,'' ``future year subaccount,'' 
and ``current year subaccount'' (and their definitions) are removed or 
replaced, as appropriate, throughout the Acid Rain Program regulations. 
The current regulations distinguish between two subaccounts in each 
unit account, i.e., the ``compliance subaccount'' for allowances usable 
for compliance in a given year and a ``future year subaccount'' for 
allowances not usable until a future year. Similarly, the current 
regulations refer to a ``current year subaccount'' of a general 
account. The electronic Allowance Tracking System does not currently 
use or refer to these subaccounts. Moreover there is also no need to 
use or refer to them when compliance is on a source-level basis. The 
proposed rule language accompanying this preamble attempts to list 
every provision in which the terms ``compliance subaccount,'' ``future 
year subaccount,'' and ``current year subaccount'' appear and to modify 
the provision as necessary to remove these terms without changing the 
substance of the provision. However, even if some instances were 
missed, EPA proposes to replace the terms in all instances and requests 
comment on, among other things, what other instances may have been 
missed.

[[Page 32701]]

    5. The provision in Sec.  73.35(b)(3) limiting the use of 
allowances from another unit at the same source for compliance is removed.
    The EPA notes, in addition to the above-described rule changes, 
shifting from unit- to source-level compliance under the Acid Rain 
Program would require revisions to the software used to operate the 
Allowance Tracking System and to reconcile allowances and emissions 
after the end of each calendar year. For example, one approach might be 
to revise the software to aggregate and convert unit accounts in the 
Allowance Tracking System to source-level compliance accounts. The 
system would need to move the allowances in the unit accounts of all 
affected units at a given source to the new source-level compliance 
account and ensure recordation in the compliance account of the 
allowances allocated to such units. In addition, annual emissions for 
the affected units at a source would have to be summed and then 
compared with the allowances in that source's compliance account. 
Because of the time necessary to revise the software and to conduct 
testing to ensure that the Allowance Tracking System operates properly, 
EPA believes that the rule changes implementing source-level 
compliance, if adopted in a final rule, should not become effective 
before July 1, 2005. Under that approach, compliance under the Acid 
Rain Program for the 2004 calendar year (which is determined after the 
allowance transfer deadline for 2004, i.e., March 1 or the next 
business day if March 1 is not a business day) would remain at the 
unit-level, and compliance would shift to the source-level for the 2005 
calendar year. An effective date of July 1, 2005 would ensure that the 
source-level rule changes would take effect after completion of the 
process of determining compliance for 2004. The EPA's experience is 
that the compliance determination process is generally completed 
several months after the end of the year for which emissions and 
allowances are compared. The July 1, 2005 effective date would give 
owners and operators, as well as EPA, the opportunity to adjust 
internal procedures to take account of source-level compliance. The EPA 
requests comment on a July 1, 2005 effective date for the Acid Rain 
Program rule changes discussed in today's notice and on any alternative 
effective dates for such rule changes.
    The EPA further notes that not only is the proposed shift to 
source-level compliance consistent with title IV and an improvement to 
the operation of the Acid Rain Program, but also this change would 
facilitate the coordination of this program with the proposed CAIR 
trading program. The latter program, of course, requires source-level 
compliance.
    The EPA is also proposing other revisions of the Acid Rain Program 
that do not address the allowance-holding requirement but that are 
focused on facilitating the interaction of the Acid Rain Program and 
the proposed CAIR trading program. For example, certain language in the 
definition of ``cogeneration unit'' in Sec.  72.2, which definition was 
recently changed (See 67 FR 40420, June 12, 2002), is changed back to 
the original language so that it is consistent with certain language in 
the proposed definition of ``cogeneration unit'' in the CAIR model 
trading rules. See section IV below.
    Further, the language required in Sec.  72.21(b)(1) for the 
certification that must be in each submission by the designated 
representative in the Acid Rain Program would be revised so that the 
same submission-certification language can be used for submissions for 
units whether the units are in both the CAIR trading program and the 
Acid Rain Program or in only one of the programs. Similarly, certain 
language required in Sec.  72.24 (paragraphs (a)(5), (a)(7), and 
(a)(10)) for the certificate of representation for the designated 
representative in the Acid Rain Program would be removed so that the 
same, standard certificate can be used for units that are in one or 
both programs. This would remove requirements (e.g., for a 1-day 
newspaper notice of the designation of a designated representative) 
that EPA believes have proved to be unnecessary. For the same reason, 
certain language required in Sec.  73.31(c)(v) for the certificate of 
representation for an authorized account representative in the Acid 
Rain Program would be removed as unnecessary. With the proposed changes 
in Sec. Sec.  72.24 and 73.31, the language for certificates of 
representation in the Acid Rain Program and the CAIR trading program 
would be the same as the language in the certificates of representation 
in the NO_X Budget Trading Program under the NO_X 
SIP Call.
    A further example is that the general requirement for all affected 
sources to submit compliance certification reports at the end of each 
year is removed as superfluous. Sources already are required to submit 
compliance certification reports under title V of the CAA that cover 
compliance with CAA requirements, including the Acid Rain Program 
requirements. Moreover, the quarterly emissions reports that each unit 
must submit already include a certification of compliance with the 
monitoring and reporting requirements under part 75 of the Acid Rain 
Program regulations. The proposed CAIR trading programs do not require 
submission of annual compliance certification reports.
    In addition, several provisions in the Acid Rain Program 
regulations concerning the allowance tracking system are proposed to be 
removed or revised in order to make the allowance tracking systems in 
the Acid Rain Program, the NO_X Budget Trading Program, and 
the proposed CAIR trading program as similar as possible. For example, 
Sec.  73.32 has proved to be superfluous (and includes obsolete 
references to compliance and current year subaccounts) and would be 
removed. Section 73.33(c) imposes a one-day newspaper notice 
requirement for authorized account representatives that has proved to 
be unnecessary and would be removed. Sections 73.37(a) through (d) 
would be removed since the claim of error procedure has proved to be 
superfluous and has not been used. Similarly, Sec. Sec.  73.50 and 
73.52 would be revised to remove superfluous language and to conform to 
the provisions under the NO_X Budget Trading Program and the 
proposed CAIR trading program. For instance, language referencing 
allowance transfers in perpetuity is removed as superfluous since such 
transfers are allowed under these sections (and in the NO_X 
Budget Trading Program) even without such language.

D. NO_X SIP Call

1. Emissions Reduction Requirements
    Today's SNPR requires additional reductions in NO_X from 
States affected by the NO_X SIP Call. However, this SNPR 
would not relieve those States from the requirements of the 
NO_X SIP Call. Except as explained below, States should 
retain all of the SIP provisions that they adopted to meet the 
requirements of the NO_X SIP Call.
    All of the States subject to the NO_X SIP Call (with the 
exception of Georgia and Missouri, which are not required to submit 
SIPs until 2005) chose to meet at least part of their emission 
reduction requirement by including their EGUs in a multi-State ozone 
season NO_X trading program. The EPA has performed modeling 
of expected NO_X emissions from EGUs assuming that all States 
affected by the proposed CAIR achieve all of their required 
NO_X reductions under the CAIR by including their EGUs in a 
regionwide annual NO_X cap-and-trade program. Based on that 
modeling, EPA has proposed that if States achieve all of the mandated 
NO_X reductions by

[[Page 32702]]

including their EGUs in the regionwide, annual NO_X cap-and-
trade program managed by EPA, EPA will consider the reductions from 
that program to also meet the ozone season reduction requirements that 
States were previously achieving from EGUs participating in a 
regionwide ozone season NO_X cap-and-trade program. Under 
these circumstances, EGUs in a State achieving all of the required 
NO_X reductions from only EGUs would not be subject to a 
seasonal NO_X cap-and-trade program unless the State elects 
to retain such a program. The EPA believes this approach would simplify 
compliance for sources and avoid the potential administrative burden of 
implementing both a seasonal and annual cap-and-trade program for EGUs.
2. NO_X SIP Call Cap-and-Trade Program for Non-EGUs
    The EPA is proposing to continue administering an ozone season only 
NO_X cap-and-trade program for non-EGUs that are subject to 
the requirements of the regionwide NO_X SIP Call cap-and-
trade program. In today's SNPR, EPA proposes modifications to part 51 
of the NO_X SIP Call to reflect the continued participation 
of non-EGUs in the ozone season NO_X cap-and-trade program 
and the removal of EGUs from their ozone season NO_X limitations.
    Maintaining the ozone season reductions from non-EGUs in the 
NO_X SIP Call is important for limiting their interstate 
contribution to ozone nonattainment. The EPA considered whether it 
would be appropriate to allow States to include non-EGUs in the annual 
CAIR trading program and relieve them from the requirements of the 
ozone season NO_X trading program. However, EPA does not have 
sufficient information to project whether non-EGUs would continue to 
meet their ozone season NO_X reduction requirements if they 
were subject to an annual limitation only. Therefore, EPA is proposing 
to continue to run the NO_X SIP Call cap-and-trade program 
for non-EGUs.
    The EPA acknowledges that, if non-EGUs are only permitted to trade 
with other non-EGUs, the robustness of the existing NO_X SIP 
Call allowance market must be maintained to provide incentives for non-
EGUs to find cost-effective emissions reductions. States that are 
concerned for the future health of the market may choose to revise 
their SIPs to achieve the non-EGU NO_X emissions reductions 
using an alternate approach. The EPA solicits comment on the potential 
effects that removing EGUs from the NO_X SIP Call trading 
market may have on the robustness of the market and any alternative 
mechanisms for addressing these concerns.
    The EPA solicits comment on the above proposal and any other 
approaches.
3. NO_X Early Reduction Credits \16\
---------------------------------------------------------------------------

    \16\ Sulfur dioxide emission reduction credits (ERCs) are not 
proposed because the CAIR sources already have incentive to make 
early, annual reductions to bank Acid Rain Program SO₂ 
allowances into the CAIR cap-and-trade program.
---------------------------------------------------------------------------

    Today's SNPR does not propose to allow the generation and use of 
early NO_X emission reduction credits (``ERCs'') but does 
solicit comment on whether NO_X ERCs should be included in 
the CAIR and, if so, how a NO_X ERC program should be 
structured.
    If NO_X ERCs are included, EPA expects that they would 
primarily be generated by sources already subject to the NO_X 
SIP Call that would choose to operate already installed selective 
catalytic reduction (SCR) technology during the 7-month ``non-ozone 
season.'' These reductions in non-ozone season NO_X 
reductions would provide some additional, early environmental benefit 
by reducing the atmospheric loading of NO_X, acid 
precipitation, and fine PM precursors prior to the implementation of 
the CAIR. That said, EPA analysis projects that over 3.7 million tons 
of NO_X ERCs could be created (between 2006 and 2010) and 
banked into the CAIR if unlimited non-ozone season ERCs were permitted 
in the program. Allowing these ERCs to be used for compliance with the 
CAIR NO_X emission cap would delay progress towards achieving 
both the annual NO_X reduction goals and could potentially 
reduce the ozone season reductions that are necessary for EPA to 
justify removing the NO_X SIP Call constraint for EGUs.
    If EPA were to include ERCs, several approaches could be utilized: 
(1) EPA could maintain the NO_X SIP Call requirements and 
allow sources to use ERCs only for compliance with the annual 
limitation, to ensure that seasonal NO_X limitations are met. 
Under this scenario, the additional States subject to the CAIR that 
have been found to significantly contribute to ozone nonattainment may 
also have to be included in the ozone season cap; (2) EPA could limit 
the period of time during which ERCs could be created and banked; (3) 
EPA could cap the amount of ERCs that can be created; and (4) EPA could 
apply a discount rate to ERCs.
    The EPA solicits comment on today's SNPR to not include 
NO_X ERCs and, if ERCs were included, how the mechanism for 
including ERCs should be structured.

E. How Would Emissions Trading Under the Proposed CAIR Relate to 
Regional Haze?

    This section addresses the relationship between the CAIR and the 
CAA visibility-impairment provisions, in particular the Best Available 
Retrofit Technology (BART) requirements under the Regional Haze Rule. 
These provisions, under CAA Section 169A-B, require certain existing 
sources, including electric generating units (EGUs) that may be 
affected by SIPs required under CAIR, to install BART. However, the 
Regional Haze Rule further provides that sources otherwise subject to 
BART may be exempt if they are subject to alternative controls 
demonstrated to provide greater reasonable progress toward the national 
visibility goal. Today, EPA proposes that BART-eligible EGUs in any 
State affected by CAIR may be exempted from BART for controls for 
SO₂ and NO_X if that State complies with the CAIR 
requirements through adoption of the CAIR cap-and-trade programs for 
SO₂ and NO_X emissions.
1. Background: Nature of Regional Haze and Visibility Impairment; 
Statutory and Regulatory Requirements
    The EPA has discussed the science and legal background for 
visibility impairment and regional haze elsewhere, most recently in the 
re-proposed Guidelines for BART Determinations (69 FR 25184, May 5, 
2004). Readers are referred to that preamble for a detailed description 
of the background. The following is a brief summary.
    a. What is regional haze? ``Regional Haze'' refers to air pollution 
that impairs visibility over a widespread area that may encompass 
several States. Regional haze occurs to varying degrees throughout the 
United States, including at national parks that may be as far as 
hundreds of miles from major pollution sources.\17\ Under sections 
169A-B of the CAA, special protection is afforded to larger national 
parks and wilderness areas, which are termed ``Class I areas.''\18\
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    \17\ National Research Council, Protecting Visibility in 
National Parks and Wilderness Areas, National Academy Press 
(Washington, DC, 1993).
    \18\ A ``Class I area'' is defined as any one of the 156 
mandatory Class I Federal areas identified in part 81, subpart D of 
title I of the CAA.
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    Visibility in Class I areas, measured as visual range, is observed 
to be on average one-half to two-thirds of the natural visual range 
that would exist in the absence of anthropogenic pollution.

[[Page 32703]]

Observations show that visibility is lowest in Class I areas in the 
eastern U.S., and significant impairment in visibility is also observed 
in the Midwest and on the Pacific coast. The best visibility occurs in 
the Central Rockies and in Alaska, but even in these locations, 
visibility is worse than would be expected without anthropogenic 
pollution.
    Most visibility impairment is caused by fine particulate substances 
and associated water. While natural sources of fine particles, such as 
forest fires and windblown dust, can affect visibility significantly, 
anthropogenic emissions are usually the major source of regional haze.\19\
---------------------------------------------------------------------------

    \19\ NARSTO, Particulate Matter Science for Policy Makers--A 
NARSTO Assessment. February 2003.
---------------------------------------------------------------------------

    b. Major chemical components of particles that contribute to 
regional haze; EGUs as the major source of those components. The major 
chemical classes of fine particles that affect visibility include 
sulfates, organic matter, elemental carbon (soot), nitrates, and soil 
dust. The major sources and important aspects of the chemistry of these 
fine particle components as they affect PM _2.5 mass were 
summarized in EPA's January 2004 proposal. (69 FR 4566, January 30, 2004).
    As discussed in the January 2004 proposal, sulfate particles 
comprise a major portion of PM_2.5 mass. The relative 
contribution of sulfates to visibility impairment is usually even 
greater than their contribution to particle mass, largely because 
sulfates absorb water, which enhances their capabilities to impair.\20\ 
Nitrates, which also generally contribute proportionally more to 
visibility impairment than they do to fine particle mass, on average 
caused 5-10 percent of visibility impairment over much of the U.S.\21\ 
Further, as discussed in section II of the January 2004 proposal, the 
chemical interplay between ammonium sulfate and ammonium nitrate 
particles is important in determining the effectiveness of 
SO₂ and NO_X reductions in reducing fine particles 
and in improving visibility. Because of this ``nitrate replacement,'' 
SO₂ controls that reduce sulfates will be more effective at 
improving visibility if complemented by NO_X controls that 
reduce nitrates, particularly in the winter.
---------------------------------------------------------------------------

    \20\ Malm, W. C., et al. (2000) Spatial and Seasonal Patterns 
and Temporal Variability of Haze and its Constituents in the United 
States: Report III, Cooperative Institute for Research in the 
Atmosphere, Colorado State University, Fort Collins, CO.
    \21\ Vimont, J. ``Nitrates: Contribution to Visibility'', 
National Park Service, Presentation to the Western Regional Air 
Partnership Workshop on NO_X, July, 2003.
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    c. Interstate transport and regional haze. A wealth of air quality 
observations and modeling data clearly demonstrate that 
PM_2.5 and its precursors are transported across State 
boundaries. This body of evidence--particularly, EPA air quality 
modeling results--was summarized in the January 2004 proposal. Sulfur 
dioxide and NO_X emissions have been demonstrated to affect 
ambient PM_2.5 concentrations over a wide interstate area. In 
addition, observations show that sulfate and nitrate make a large 
contribution to visibility impairment.\22\
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    \22\ Malm, W. C., et al. (2000) Spatial and Seasonal Patterns 
and Temporal Variability of Haze and its Constituents in the United 
States: Report III, Cooperative Institute for Research in the 
Atmosphere, Colorado State University, Fort Collins, CO.
---------------------------------------------------------------------------

    A large fraction of current and future SO₂ and 
NO_X emissions are attributable to EGUs. In the lower 48 
States, the fraction of SO₂ emissions from EGUs is a 
consistent percentage of emissions from all sources, ranging from 62 to 
65 percent over time; and EGU NO_X emissions as a percent of 
emissions from all sources is projected to grow slightly from 21 to 25 
percent.
    d. What are the Clean Air Act requirements for addressing regional 
haze? In the 1977 CAA, Congress added the first provisions to protect 
visibility in Class I areas. Subsection (a)(1) of CAA section 169A 
establishes the following national visibility goal: ``The prevention of 
any future, and the remedying of any existing, impairment of visibility 
in mandatory Class I Federal areas which impairment results from 
manmade air pollution.'' Subsection (a)(4) of this provision requires 
EPA to promulgate regulations to assure ``reasonable progress toward 
meeting [this]
national goal. * * *'' In addition, the CAA visibility 
provisions contain a specific requirement for the installation of BART 
at certain existing sources, discussed below.
    In 1980, EPA issued regulations addressing visibility impairment 
``that can be traced to a single existing stationary facility or small 
group of existing facilities.'' (45 FR 80085, December 2, 1980). In 
that rulemaking, the Agency explicitly deferred national rules 
addressing regional haze impairment.
    In 1990, Congress added section 169B to the CAA to prompt EPA to 
address regional haze. These provisions specifically establish a 
commission for Grand Canyon National Park--the Grand Canyon Visibility 
Transport Commission (GCVTC)--and require the Commission to issue a 
report to EPA recommending measures to remedy visibility impairment. 
CAA Section 169B(a)-(d) and (f). In the 1990 CAA Amendments, Congress 
further provided that within 18 months after receiving this final 
report, EPA must ``carry out the Administrator's regulatory 
responsibilities under [section 169A], including criteria for measuring 
`reasonable progress' toward the national goal.'' CAA Section 
169B(e)(1).
    The EPA published a rule in 1999 to address various aspects of 
regional haze (the Regional Haze Rule). (64 FR 35714, July 1, 1999). 
The Regional Haze Rule calls for the States to play the lead role in 
designing and implementing regional haze programs for Class I areas. 
Each State must establish goals that provide for reasonable progress, 
over the period covered by the SIP, toward achieving natural visibility 
conditions in the Class I areas in that State. 40 CFR 51.308(d)(1). 
States must also submit a long-term strategy, as well as measures 
necessary to implement that strategy, addressing visibility impairment 
due to regional haze for each Class I area in the State and for each 
Class I area located outside the State which may be affected by 
emissions from the State. 40 CFR 51.308(d)(1), (3).
    The EPA provided the States with considerable flexibility in 
selecting the reasonable progress goals. The Regional Haze Rule 
requires that these goals both provide for improvement during the 20 
percent most impaired days and ensure no degradation in visibility 
during the 20 percent clearest days. The baseline period for assessing 
improvement and degradation is 2000-2004. In addition, for each Class I 
area within its borders, a State must determine the appropriate, annual 
rate of visibility improvement that would lead to ``natural 
visibility'' conditions. The rule includes a presumption that States 
can reach this goal in 60 years. 40 CFR 51.308(d)(1)(ii). Under the 
regulations, this 60-year period extends to 2064, with the first long-
term strategy period ending in 2018. 40 CFR 51.308(f). States must 
submit their long-term strategies each 10-year period. The first 
strategy is due in early 2008 and must provide for reasonable progress 
through 2018.
    The 1999 Regional Haze Rule also addressed the BART requirements, 
in 40 CFR 51.308(e)(1), and provided for the use of alternative 
measures in lieu of BART in 40 CFR 51.308(e)(2) (discussed more fully 
in section III.E.1.e. of this preamble below). The Regional Haze Rule 
was challenged by several petitioners in the U.S. Court of Appeals for 
the DC Circuit. American Corn

[[Page 32704]]

Growers et al. v. EPA, 291 F.3d 1 (DC Cir., 2002). The Court generally 
upheld EPA's approach to improving visibility. However, the Court 
vacated and remanded the provisions of the rule addressing the 
determination of BART on a case-by-case basis.
    In addition to these nationally applicable reasonable progress 
requirements, the Regional Haze Rule contains a special rule for the 
nine-State region \23\ (including tribes) included in the GCVTC, with 
respect to the Grand Canyon and 15 other Class I areas located on the 
Colorado Plateau. Under this provision, these States (and tribes) may 
meet their reasonable progress requirements for the first, long-term 
strategy period (ending in 2018) with respect to these 16 Class I areas 
either by (i) meeting the nationally applicable reasonable progress 
requirements (40 CFR 51.308), or (ii) adopting the recommendations of 
the GCVTC, once those recommendations were approved by EPA. 40 CFR 
51.309. This section also provided that, before the GCVTC 
recommendations could be approved, an ``Annex'' to those 
recommendations pertaining to stationary sources must be submitted to 
EPA, providing quantitative emissions reduction goals and detailed 
implementation strategies. The successor organization to the GCVTC--the 
Western Regional Air Partnership (WRAP)--submitted such an Annex in 
September, 2000, and EPA approved it in a final rule by notice dated 
June 5, 2003. (68 FR 33764).
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    \23\ The nine States are Arizona, California, Colorado, Idaho, 
Nevada, New Mexico, Oregon, Utah, and Wyoming.
---------------------------------------------------------------------------

    e. Statutory and regulatory background for BART requirement. Under 
CAA Section 169A(b)(2)(A), an existing source must install BART if the 
source was constructed between 1962 and 1977,\24\ falls within one of 
26 categories, has a potential to emit 250 tons or more of any 
pollutant, and emits ``any air pollutant which may reasonably be 
anticipated to cause or contribute to any impairment of visibility'' at 
a Class I area. The 1999 Regional Haze Rule, among other things, 
established requirements for implementing BART on a source-by-source 
basis, in order to address the contribution of BART-eligible sources to 
regional haze. 40 CFR 51.308(e)(1).
---------------------------------------------------------------------------

    \24\ Specifically, a source is subject to the BART requirement 
if it came on-line after August 7, 1962 and construction commenced 
prior to August 7, 1977.
---------------------------------------------------------------------------

    In addition to requirements for implementing BART on a source-by-
source basis, the 1999 rule provides States with an option of using an 
emissions trading program or alternative measure in lieu of requiring 
source-by-source BART. 40 CFR 51.308(e)(2). States may utilize this 
trading or alternative option if they demonstrate that it would achieve 
greater reasonable progress than source-by-source BART. To make this 
demonstration, States would compare the estimated emissions reductions 
available from requiring BART on all BART-eligible sources, and the 
resulting degree of visibility improvement expected. Under the existing 
section 308(e)(2) States would also have to ensure that the trading or 
alternative measure applied to all BART-eligible sources in all 26 
categories, within the State.\25\
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    \25\ In section III.E.3 in this supplemental proposal, EPA is 
proposing to amend section 308(e) to eliminate the requirement to 
address all 26 categories simultaneously under specific conditions 
relating to the proposed CAIR.
---------------------------------------------------------------------------

    In July 2001, we proposed guidelines for implementing BART on a 
source-specific basis. These guidelines also contained guidance on how 
to demonstrate that a proposed alternative to BART would result in 
greater progress than source-specific BART. (66 FR 38108, Friday, July 
20, 2001).
    By notice dated May 5, 2004, we re-proposed the BART regulations 
and guidelines, to comport with the court's findings regarding source-
specific BART. The portions of the BART guidelines related to 
demonstrating that an alternative is better than BART are largely 
unchanged from the 2001 proposal. (69 FR 25184, 25186).
2. What Is the Basis for This SNPR That the Cap-and-Trade Program is 
``Better Than BART'' for Affected EGUs?
    In today's SNPR, EPA proposes to apply the better-than-BART 
requirements to the CAIR proposal, as it may affect the 29 States and 
DC in the eastern part of the country. Specifically, EPA proposes that 
BART-eligible EGUs in any State affected by CAIR may be exempted from 
BART if that State complies with the CAIR requirements through adoption 
of the CAIR cap-and-trade programs for SO₂ and 
NO_X for affected EGUs.
    a. Better-than-BART two-pronged test. In our recently re-proposed 
Guidelines for BART Determinations, we propose a methodology for 
determining whether a trading program will provide greater reasonable 
progress than BART. If the geographic distribution of emissions 
reductions is similar under either program a State may demonstrate the 
trading program is better than BART by showing that the trading program 
achieves greater emissions reductions than the source-specific BART 
program. If it is expected that the trading program would result in a 
different geographic distribution of emissions reductions than would 
source-specific BART, visibility impacts must be assessed through a 
two-pronged test. (69 FR 25184, 25231, May 5, 2004). Although under 
CAIR the total emissions reductions are greater than source-specific 
BART would achieve in the CAIR States, our modeling indicates that CAIR 
would produce greater emissions reductions than BART in most States, 
but lesser reductions in a few States. Because of this potential for a 
different geographic distribution of emission reductions, we have 
assessed the difference between the two programs under the two-pronged 
visibility impact test.
    The first prong is designed to address the ``prevention of any 
future'' impairment element of the CAA section 169A(a)(1) national 
visibility goal. Under this prong, visibility must not decline at any 
Class I area, as determined by comparing the predicted visibility 
impacts at each affected Class I area under the trading program with 
existing visibility conditions. This prong also protects against the 
creation of visibility impairment ``hot spots'' that could conceivably 
occur as the result of local emissions increases under a trading program.
    The second prong of the test is designed to address the ``remedying 
of any existing'' impairment element of the CAA section 169A(a)(1) 
national visibility goal. Under this prong, at the end of the first 
long-term strategy period in 2018, overall visibility, as measured by 
the average improvement at all affected Class I areas, must be better 
under the trading program than under source-specific BART.
    We also note that the two-pronged test does not require that the 
comparison be limited to BART-eligible sources affected by the 
alternative-to-BART programs. In other words, one way the alternative 
program may be better than source-specific BART is by controlling 
emissions from non-BART eligible sources within the affected source 
categories. This was the case in our approval of the WRAP Annex as 
better than BART under Regional Haze Rule section 40 CFR 51.309. (See 
68 FR 33769).
    b. Application of the two-pronged test to the CAIR proposal. To 
determine whether CAIR is better than BART, the analysis must address 
the two main elements of the test. First, we compare the existing 
visibility situation (using data from the baseline period 2000-2004) to 
a future where CAIR is in effect to see if any degradation occurs. 
Second, we compare the visibility

[[Page 32705]]

improvements resulting from the CAIR cap-and-trade program to 
visibility improvements expected from the application of source-
specific BART in 2015, near the end of the first long-term strategy 
period in 2018.
    In applying the two prongs of the test, we faced some shortcomings 
in currently available modeling. Under both prongs, we would ideally 
perform air quality modeling for the situation where CAIR is in effect 
only in the CAIR region, and source-specific BART is in effect in the 
rest of the country. This would reflect the best currently available 
prediction of future emissions, because BART is a federally enforceable 
requirement of the CAA, and therefore appropriately assumed to be in 
effect outside the CAIR region.\26\
---------------------------------------------------------------------------

    \26\ The existence of BART outside the CAIR region would also 
mitigate concerns of emissions leakage caused by production and 
emissions shifts from the CAIR region, which might occur if non-CAIR 
States are subject to substantially less stringent requirements.
---------------------------------------------------------------------------

    However, the CAIR air quality modeling was based on the simplifying 
assumption that SO₂ emission reductions would be required 
nationwide and did not include BART SO₂ controls in place 
for the non-CAIR region. Additionally, NO_X was controlled in 
a 31\1/2\ State region rather than the 29 State region that is covered 
in the proposed CAIR.\27\ Finally, because the recently re-proposed 
BART guidelines are applicable nationally, for that rulemaking we 
estimated emissions after application of source-specific BART on a 
nationwide basis. We therefore currently lack modeling of a scenario 
where BART is applied only outside the CAIR region.
---------------------------------------------------------------------------

    \27\ The modeling assumed NO_X reductions in 5 States 
where they are not required (Maine, New Hampshire, Rhode Island and 
Vermont). Additionally it does not require controls in Kansas and 
the western half of Texas. Kansas and the all of Texas are covered 
by CAIR.
---------------------------------------------------------------------------

    Despite these limitations in currently available modeling, we 
believe the ideal scenario and the modeling we conducted using 
available information are similar enough to serve as the basis of this 
``better than BART'' determination. In fact, we anticipate that when we 
model a scenario combining CAIR requirements in the CAIR region with 
source-specific BART in the rest of the country, we will project fewer 
SO₂ and NO_X emissions than our current modeling 
indicates. The full rationale for this belief is given in a technical 
support document (SAQMTSD)\28\. The remainder of this section gives a 
brief overview of key aspects of the methodology we used and the results.
---------------------------------------------------------------------------

    \28\ See ``Supplemental Air Quality Modeling Technical Support 
Document for the Clean Air Interstate Rule (May 2004),'' available 
in the docket.
---------------------------------------------------------------------------

    We used the Integrated Planning Model (IPM) to estimate emissions 
expected after implementation of a source-specific BART approach and 
after implementation of the CAIR cap-and-trade programs for EGUs. This 
analysis indicates that implementing BART on a source-specific basis 
would result in SO₂ emissions falling to approximately 6.9 
million tons nationally in 2015, then increasing, thereafter \29\. 
Under the CAIR trading program, however, SO₂ emissions in 
2015 would fall to about 5.3 million tons nationwide, and would 
continue declining to 4.3 million tons in 2020 \30\. Notably, CAIR 
leads to SO₂ emission reductions when it starts in 2007 that 
grow over time. Nationwide, NO_X emissions under a source-
specific BART approach would be reduced to 2.7 million tons per year in 
2015 and do not decrease thereafter \31\, while under the proposed CAIR 
trading program NO_X emissions would be 2.2 million tons 
nationwide in 2015 and 2.3 million tons in 2020.\32\ Notably, 
substantial NO reductions actually begin in 2010 under the CAIR rule.
---------------------------------------------------------------------------

    \29\ As discussed in the SAQMTSD, the amount of SO₂ 
emissions remaining after the application of BART on all BART-
eligible EGUs may be somewhat less than 6.9 million tons by 2015. 
This is so because we modeled emissions reductions only for BART-
eligible EGUs over 250 MW and did not include BART-eligible EGUs 
between 25 and 250 MW. We anticipate that even with any additional 
SO₂ reductions from these smaller EGUs the amount of 
remaining SO₂ emissions under the CAIR cap-and-trade 
program will be sufficiently less than under BART to support our 
proposed determination that CAIR provides greater visibility 
improvement than BART for EGUs. We intend to do further analysis of 
the effect of applying BART controls to EGUs between 25 and 250 MW.
    \30\ Under the cap-and-trade program, SO_X emissions 
do not reach their minimum until after the 2015 Phase-2 
implementation date because the availability of an existing title IV 
allowance bank. Sources may use allowances from this bank to emit at 
higher levels until sometime after 2020 when all of the banked 
allowances have been used.
    \31\ As in the case of SO₂ emissions noted above, the 
SAQMTSD explains that the application of BART on all BART-eligible 
EGUs may result in somewhat fewer NO_X emissions than 2.7 
million tons by 2015, once emission reductions from BART-eligible 
EGUs between 25-250 MW are considered. As with SO₂, we 
anticipate that CAIR would nonetheless provide greater 
NO_X emission reductions than BART, and we intend to do 
further analysis of the effect of including BART-eligible EGUs 
between 25-250 MW.
    \32\ There is much less incentive to bank allowances under the 
NO_X program so the emissions caps should be met in 2015. 
Since the emissions cap is not nationwide there is an increase in 
NO_X emissions in the non-affected States after 2015.
---------------------------------------------------------------------------

    We then used the REMSAD air quality model \33\ to project the 
visibility impact of these IPM emissions predictions for both the CAIR 
and the nationwide source-specific BART scenario. Specifically, EPA 
evaluated the model results for the 20 percent best days (that is, 
least visibility impaired) and the 20 percent worst days at 44 Class I 
areas.\34\ These 44 areas are broadly representative of national 
visibility conditions, as they are found in States throughout the 
country, including California and Texas, States on the continental 
divide, the Pacific Northwest, the Southwest, the Southeast, the Mid-
Atlantic, and New England. Thirteen of these Class I areas are within 
States affected by the CAIR proposal, and 31 Class I areas are outside 
the CAIR region--29 in States to the west of the proposed CAIR region, 
and 2 in New England States northeast of the CAIR region. We also 
modeled expected visibility for the future base case, which has lower 
emissions than we have today overall (that is, we examined expected 
emissions levels in 2015 without either BART or the trading program, 
but including emissions reductions anticipated from other 
requirements.) This is a more stringent way of considering degradation, 
given we are primarily concerned about degradation relative to the 
existing visibility situation.
---------------------------------------------------------------------------

    \33\ Changes in future visibility were predicted by using the 
REMSAD model to generate relative visibility changes, then applying 
those changes to measured current visibility data. Details of the 
visibility modeling and calculations can be found in SAQMTSD.
    \34\ Ambient PM2.5 data for the purposes of calculating 
visibility degradation at Class I areas is collected by the IMPROVE 
network. There are currently 110 IMPROVE monitoring sites operating 
at Class I areas. For this analysis, future year visibility values 
were calculated at the 44 IMPROVE sites which had complete data in 
1996. Since the base year meteorology used in the REMSAD modeling is 
from 1996, ambient data from 1996 is needed to be able to apply the 
model results. It is necessary to know which days make up the 20 
percent best and worst days so that the model outputs can be 
calculated on the same days. For a Class I area without ambient data 
in 1996, there is no way to match up the model predicted changes in 
visibility with the ambient data from the 20 percent best and worst 
days. There were only 44 IMPROVE sites (at Class I areas) with 
complete data for 1996.
---------------------------------------------------------------------------

    i. First prong: Visibility will not decline at any class I area. 
The modeling predicts that the CAIR cap-and-trade program will not 
result in degradation of visibility, compared to existing visibility 
conditions, at any of the 44 Class I areas considered. In each of the 
44 areas--the 13 within the proposed CAIR region and the 31 outside of 
it--visibility is expected to improve or at worst remain unchanged. 
Details of these results, for the 20 percent worst days and the 20 
percent best days are contained in SAQMTSD. We only had modeling 
representing nationwide SO₂ emission reductions, including 
some

[[Page 32706]]

relatively small amount of SO₂ emission reductions occurring 
in the West \35\. Since the western SO₂ emissions reductions 
are relatively small, EPA believes they will not significantly impact 
the conclusions of this analysis.
---------------------------------------------------------------------------

    \35\ Although the CAIR proposal would not include emissions 
reductions requirements for western States, BART requirements will 
otherwise apply in these States and achieve some level of 
SO₂ reductions.
---------------------------------------------------------------------------

    Based on these results and other analysis presented in the SAQMTSD, 
we believe the CAIR impact on emissions passes the first prong of the 
two-pronged test by not causing degradation of visibility at any Class 
I area.
    ii. Second prong: Average visibility for all affected Class I areas 
will improve. The second prong of the better-than-BART test is to 
analyze whether the CAIR cap-and-trade programs result in greater 
overall improvement in visibility, as compared to source-specific BART.
    For Class I areas in the proposed CAIR region, our analysis 
indicates that proposed CAIR emissions reductions in the East produce 
significantly greater visibility improvements than source-specific 
BART. Specifically, for the 15 Eastern Class I areas analyzed, the 
average visibility improvement (on the 20 percent worst days) expected 
solely as a result of the CAIR is 2.0 deciviews (dv), and the average 
degree of improvement predicted for source-specific BART is 1.0 dv. 
Therefore, the proposed CAIR is substantially better than BART--indeed, 
the proposed CAIR provides more than twice the visibility improvement 
benefits--for Eastern Class I areas.\36\
---------------------------------------------------------------------------

    \36\ We note that the modeling we used to represent the CAIR 
proposal was more stringent than the proposed CAIR in some ways 
(because it assumed SO₂ reductions in the West and 
NO_X reductions in the Northeast, which the proposed CAIR 
does not require) and less stringent in others (because it does not 
include NO_X controls for Kansas and western Texas, which 
are required in the proposed CAIR). As explained in the SAQMTSD, we 
anticipate that these differences are either too small to affect the 
analysis, or are mitigated by the fact that source-specific BART 
will produce SO₂ and NO_X reductions in the 
non-CAIR States in which our modeling attributed emissions 
reductions to CAIR. Therefore, we believe that the air quality 
modeling supports our better-than-BART determination.
---------------------------------------------------------------------------

    Similarly, on a national basis, the visibility modeling shows that 
for the 44 class I areas evaluated, the average visibility improvement, 
on the 20 percent worst days, in 2015 was 0.7 dv under the proposed 
CAIR cap-and-trade programs, but only 0.4 dv under the source-specific 
BART approach.
    We therefore believe that these results, in combination with the 
other analysis in the SAQMTSD, demonstrate that the second prong of the 
better-than-BART test is met.
    Because both prongs of the test are met, EPA proposes to conclude 
that the proposed CAIR cap-and-trade program is better than BART for 
BART eligible EGUs within the proposed CAIR region. Therefore, States 
that adopt the model cap-and-trade programs would not be required to 
implement source-specific BART for their EGUs.
3. What Changes to the Regional Haze Rule Provisions for Alternatives 
to BART Are Proposed?
    The preceding discussion applied the provisions of section 40 CFR 
51.308(e)(2) of the Regional Haze Rule which allows States to determine 
that a trading program or other alternative measure may be substituted 
for individual BART applications for all sources subject to the BART 
requirement.
    Because the proposed CAIR allows States to choose how to achieve 
the required emissions reductions, and does not mandate participation 
in the EPA-administered cap-and-trade program for EGUs, some States may 
wish to satisfy their proposed CAIR requirements through controls on 
sources other than EGUs, or through controls on EGUs without using the 
CAIR cap-and-trade programs (such as through an in-State only trading 
program). To the extent that these control obligations fall on BART-
eligible sources, the State may wish to demonstrate that these controls 
are better than BART, and therefore satisfy the source-specific BART 
requirements for those sources.
    To accommodate the various approaches States may wish to take in 
complying with the proposed CAIR and making the better-than-BART 
determinations, we propose to add a new section to the alternative-to-
BART provisions of the Regional Haze Rule. We are not proposing to 
change or revise the provisions contained in section 308(e)(2), which 
apply to States that develop their own cap-and-trade program or other 
alternative measure to BART. Therefore, we are retaining 308(e)(2) 
without revision, except for the addition of a proposed cross-reference 
to the new provision for these BART-alternative rules proposed today. 
Section 308(e)(2) will continue to apply to trading programs or other 
alternatives to BART which do not involve the proposed CAIR cap-and-
trade programs. These might include in-State only trading programs, or 
future regional trading programs developed by States and tribes through 
Regional Planning Organizations.
    We propose to add a new section 308(e)(3), which provides that for 
any of the 29 States and DC in the CAIR region, implementation of the 
CAIR cap-and-trade programs to fulfill the proposed State emissions 
reduction obligations under the CAIR qualifies as a ``better than 
BART'' alternative. This alternative is available only to States that 
subject all of their EGUs to the cap-and-trade programs. As explained 
above, modeling to support the proposed determination establishes that 
the cap-and-trade programs would result in greater reasonable progress 
than would source-specific BART for EGUs. Therefore, a better-than-BART 
demonstration would not be required of States that choose this option.
    We also propose to renumber current sections 308(e)(3) and (4) to 
read 308(e)(4) and (5), respectively. These sections provide for 
continuing regulation of BART-eligible sources under the general 
regional haze provisions after BART is satisfied, and for source-
specific exemptions from the Administrator.
4. What Effect Does the CAIR Cap-and-Trade Program Have on Source-
specific BART Based on Reasonably Attributable Visibility Impairment?
    As we explained in our recent re-proposal of the BART guidelines 
(69 FR 25184, May 5, 2004), when a State utilizes an alternative 
measure such as an emissions trading program in lieu of requiring BART 
on specific sources, the requirement for BART is not satisfied until 
the alternative measure reduces emissions sufficiently to make ``more 
reasonable progress than BART.'' Thus, in that period between 
implementation of an emissions trading program and the satisfaction of 
the overall BART requirement, an individual source could be required to 
install BART for reasonably attributable impairment under 40 CFR 
51.302. The Regional Haze Rule contains a provision allowing for 
``geographic enhancements'' to address the interface between a regional 
trading program and the requirement under 40 CFR 51.302 regarding BART 
for reasonably attributable visibility impairment. (See 40 CFR 
51.308(e)(2)(v)).
    We note that the same framework applies in the context of the 
proposed CAIR cap-and-trade programs. That is, until the emissions 
reductions requirements in today's SNPR are fully implemented in 2015, 
the possibility exists that a certification of impairment by a Federal 
Land Manager (FLM) could trigger a requirement for a State to determine 
whether the impairment is ``reasonably attributable'' to a single

[[Page 32707]]

source or small group of sources, and if so to make a source-specific 
BART determination. We request comments on whether a ``geographic 
enhancement'' (for example, an adjustment to the State's allowance 
budget) would be appropriate, and whether such enhancement mechanisms 
should be determined by EPA on a national basis, or individually by 
affected States.
    We also note that the WRAP, as part of its voluntary emissions 
milestones and backstop SO₂ cap-and-trade program under 
Regional Haze Rule section 309 has adopted policies which target use of 
the Sec.  51.302 provisions by the FLMs. In this case, for the five 
States in the WRAP program, the FLMs have agreed that they will certify 
reasonable attributable impairment only under certain specific 
conditions. Under this approach, the FLMs would certify under 40 CFR 
51.302 only if the regional trading program is not decreasing or has 
not decreased sulfate concentrations in a Class I area within the 
region. Moreover, the FLMs will certify impairment under 40 CFR 51.302 
only where: (1) BART-eligible sources are located ``near'' that class I 
area and (2) those sources have not implemented BART controls. In 
addition, the WRAP is investigating other procedures for States to 
follow in responding to a certification of reasonably attributable 
impairment if an emissions trading approach is adopted to address the 
BART requirement based on the sources' impact on regional haze.
    We request comment on whether such an approach would be appropriate 
for the proposed CAIR cap-and-trade programs.

F. Tribal Issues

    As discussed in our January 2004 proposal, tribal implementation of 
approved CAA programs is optional. That is, under CAA section 301(d) as 
implemented by the Tribal Authority Rule (TAR), eligible Indian tribes 
may implement all, but are not required to implement any, programs 
under the CAA for which EPA has determined that it is appropriate to 
treat tribes similarly to States. Tribes may also implement 
``reasonably severable'' elements of programs. (40 CFR 49.7(c)). In the 
absence of tribal implementation of a CAA program or programs, EPA will 
utilize Federal implementation for the relevant area of Indian country 
as necessary or appropriate to protect air quality, in consultation 
with the tribal government. State implementation plans are generally 
not applicable in Indian country.
    With very few exceptions, Indian country is not home to the types 
of air pollution sources potentially affected by this rule--neither 
EGUs, nor other large sources of NO_X or SO₂ that 
could be controlled in order to meet emission reduction requirements.
    Despite these legal and factual considerations which indicate that 
today's proposal would not generally immediately affect tribes, tribes 
have raised valid concerns about the rule's future implications. These 
implications arise from the fact that the cap-and-trade program by 
definition is designed to cap emissions over a broad geographic area 
and constrain these emissions into the future. Indian country lands are 
included within these broad areas. Some tribes may choose to pursue a 
path of economic development which may include future sources of air 
pollution.
    The TAR contains a list of provisions for which it is not 
appropriate to treat tribes in the same manner as States. 40 CFR 49.4. 
The CAIR proposal is based on the States' obligations under CAA 
110(a)(2)(D) to prohibit emissions which would contribute significantly 
to non-attainment in other States due to pollution transport. Because 
CAA 110(a)(2)(D) is not among the provisions we determined to be not 
appropriate to apply to tribes in the same manner as States, the CAIR 
is applicable to tribes. However, among the CAA provisions not 
appropriate for tribes are ``[s]pecific plan submittal and 
implementation deadlines for NAAQS-related requirements * * *'' 40 CFR 
49.4(a). Therefore, tribes are not required to submit implementation 
plans under the CAIR. Instead, the CAIR will be implemented as 
necessary or appropriate in Indian country, either through voluntary 
Tribal Implementation Plans or Federal Implementation Plans developed 
in consultation with affected tribes.
    The EPA believes new sources that locate in Indian country should 
be subject to the program in the same manner as any new source located 
outside of Indian country. If they were not, emissions from new Indian 
country sources could jeopardize the environmental goals of PM2.5 and 
ozone attainment on which today's rule is based. It could also 
conceivably result in undue pressure for energy and economic 
development in Indian country, depending on allowances, prices and a 
variety of other economic and regulatory factors.
    At the same time, some tribal representatives have voiced another 
set of concerns to EPA. In their view, requiring new sources in Indian 
country (which may be tribally owned) to either obtain an allocation of 
allowances from the State where the tribe is located, or to purchase 
allowances in order to operate is unfair, for several reasons. These 
include: (1) That the concept that budgets for Indian country should be 
derivative from State budgets may offend notions of tribal sovereignty 
and autonomy; (2) that Federal policy over the course of U.S. history 
has hindered tribal economic development and this inequity should not 
be continued by basing allocations on existing source emissions; (3) 
that some of the tribes that have contributed substantially to the 
economy through extractive industries have not shared in the economic 
benefits, including residential electrification; and (4) that Indian 
country areas may have suffered the detrimental effects of air 
pollution from the sources from which they would be required to buy 
allowances in order to construct new sources.
    One approach that might be used to address these concerns would be 
to develop a Federal set-aside of allowances for new sources in Indian 
country. The WRAP, in developing a backstop cap-and-trade program for 
SO₂ under section 40 CFR 51.309 of the Regional Haze Rule, 
addressed this same set of concerns. The WRAP is a unique partnership 
of 13 western States, tribes, and Federal agencies. The WRAP Board 
comprises equal numbers of State governors and tribal leaders, or their 
designees, and decisions are made by consensus.
    Based on tribal input, the WRAP included provisions to address the 
tribal concerns delineated above including a tribal set-aside of 20,000 
tons of SO₂ per year. This amount was not the product of any 
single formula, but was negotiated within the WRAP based on a number of 
factors. One important consideration was that because new EGUs and 
other major sources would be subject to pre-construction permitting 
under New Source Review (NSR) or Prevention of Significant 
Deterioration (PSD) rules, as well as New Source Performance Standards 
(NSPS) or Maximum Achievable Control Technology (MACT), SO₂ 
emissions per MW or other unit of production would be considerably 
lower than for older, less efficient plants. Therefore, although 20,000 
tons represents only about 4 percent of the 9-State cap for 2018, it 
would enable the installation of a much larger percentage of new 
capacity.
    The WRAP's cap-and-trade program will only come into existence if 
voluntary efforts and current requirements fail to meet the agreed upon 
emissions reduction ``milestones.'' Therefore, the tribal set-aside, 
like all tradable allowances under this program,

[[Page 32708]]

will only exist if the milestones are not met sometime between 2003 and 
the end of the first long-term strategy period in 2018. In light of the 
uncertainty of this event, and of the difficulty of reaching consensus 
among the more than 200 tribes in the affected region, the WRAP did not 
attempt to establish the mechanism by which the tribal set-aside would 
be allocated among tribes. Rather, it was agreed that this mechanism 
would be determined within one year of the date the trading program was 
triggered, by a determination that the milestones had been exceeded. 
This would provide for the distribution of all allowances by the time 
of trading program implementation.
    Tribal participants in the WRAP stipulated that the tribal set-
aside allocations would be available to tribes for use by new sources, 
for sale to generate revenue, or to retire for the benefit of the 
environment. The EPA concurred with these uses in the preamble to the 
final WRAP Annex rule (68 FR 33778, June 5, 2003). We also agreed that 
tribal participation in the Annex, including the tribal set-aside, is 
not dependent on whether the State in which the tribe is located 
participates. For the few sources currently in existence in Indian 
country within the WRAP region which are eligible for the program based 
on SO₂ emissions, the WRAP would provide for allowance 
allocations within the existing-source cap. These sources would not 
need to draw upon the tribal set-aside for the allowances to cover 
their emissions.
    There are no emission sources in Indian country of which we are 
aware in the 29-State region that could be affected by the January 2004 
proposal. (We request comment regarding the existence of any such 
sources of which we are unaware). Therefore, the only way tribes in 
this region could receive allowances would be through a set-aside.
    The approach used by the WRAP could provide a template for the CAIR 
for both SO₂ and CO_X set-asides for tribes. This 
would raise a number of issues, some identical to those faced by the 
WRAP and some with different considerations. For example, one 
difference is that because the CAIR is not a backstop cap-and-trade 
program, any allowance set-aside for tribes would either result in a 
corresponding decrease in the present allowances of existing sources, 
or increase the overall level of the cap.
    The WRAP example of establishing a tribal set-aside provides one 
possible approach to addressing tribal concerns. If EPA were to 
determine that a tribal set-aside were appropriate, some issues raised 
in developing the set-aside would include: (1) What method to use to 
determine the SO₂ and NO_X set-asides, for example 
through negotiation or by a formula, (2) whether the set-aside would be 
in addition to or part of the allocations proposed in our January 2004 
proposal, and (3) how the tribal set-aside would be allocated or 
distributed among tribes, for example on a first-come first-served 
basis, by an allocation formula, or some combination of approaches.
    We seek comment on whether a tribal set-aside is necessary or 
appropriate; if so, how it should be structured; whether other 
approaches might better address the tribal concerns identified above. 
We also seek comment on any other implications the proposed CAIR may 
have for tribes. We remain committed to fulfilling our obligation to 
consult with tribes, and will continue to do so as we address these 
issues.

IV. Model Cap-and-Trade Rule

A. Background and Purpose of the Model Rules

    This section of today's action proposes model trading rules--one 
for SO₂ and one for NO_X--that States will adopt 
if they wish to participate in the EPA-managed, EGU cap-and-trade 
program to achieve the emissions reductions of the proposed CAIR. This 
fulfills the commitment made in the January 2004 proposal.
    Today's action proposes a NO_X and a SO₂ model 
cap-and-trade rule for public comment. At the time of signature of 
today's SNPR, EPA had not yet reviewed full public comment on the 
January 2004 proposal, which solicited comment on some model rule 
concepts. The EPA intends to respond to comments received on the 
January 2004 proposal and today's SNPR when it promulgates the final rule.
    The NO_X and SO₂ model rules incorporate the 
experience gained through the implementation of several cap-and-trade 
programs (i.e., the CAA title IV SO₂ Acid Rain Program, the 
Ozone Transport Commission Regional NO_X Program, and the 
NO_X SIP Call), lessons learned from other trading programs 
like the Regional Clean Air Incentives Market (RECLAIM), as well as two 
workshops which EPA held to inform this rulemaking. These workshops, 
held in July and August of 2003, provided a forum for States and multi-
State air planning organizations to share with EPA what has worked 
well, what may not have worked well, and what could be improved. (The 
EPA Web site provides a summary of the comments received from these 
workshops at http://www.epa.gov/airmarkets/business/noxsip/atlanta/
atl03.html). Workshops such as these played an important role in the 
development and implementation of the NO_X SIP Call and aided 
in the development of this proposed rule.
    This section describes: The advantages of adopting the model 
trading rules; the requirements for those who choose to adopt the model 
rules; the flexibility that States have in developing their cap-and-
trade rules; and, lastly, a subpart-by-subpart explanation of the model 
rule provisions that highlights key elements and aspects unique to 
either the SO₂ or NO_X programs.
1. Who May Adopt the Model Rules and What Are the Advantages of 
Adopting New Model Rules?
    States may choose to participate in the EPA-managed cap-and-trade 
programs, which are a fully approvable control strategy for achieving 
all of the emissions reductions required under today's proposed 
rulemaking, in order to achieve the mandated emission reductions in a 
highly cost-effective manner. States that wish to reduce emissions by 
controlling EGUs (which modeling shows can make additional highly cost-
effective emission reductions) through a regionwide cap-and-trade 
approach may simply adopt the model rules and comply with the 
requirements for Statewide budget demonstrations detailed in section 
III. States that elect to achieve the required reductions by regulating 
other sources or using other approaches, should refer to section III 
for alternate State requirements.
    Today's action proposes that States that choose to achieve the 
mandated emission reductions through the EPA-managed cap-and-trade 
programs are also required to adopt both the SO₂ and 
NO_X model rules. Requiring States to participate in both the 
SO₂ and NO_X programs assures that compliance is 
more readily determinable, and creates incentives for sources to 
develop comprehensive control strategies for both pollutants.\37\
---------------------------------------------------------------------------

    \37\ Note that under the proposed CAIR, because Connecticut is 
only required to reduce NO_X emissions in the summertime 
to address its impact on downwind 8-hour ozone nonattainment areas, 
Connecticut would not be required to adopt the CAIR NO_X 
model rule--which focuses on annual NO_X reductions--
unless the State volunteers to make annual NO_X reductions.

---------------------------------------------------------------------------

[[Page 32709]]

Advantages of Adopting the Model Rules

    EPA is proposing the use of regionwide cap-and-trade programs 
because market-based approaches have proven to be both environmentally 
effective and cost-effective. The advantages of a well-designed cap-
and-trade system include:
    ? Control of emissions to desired levels under a fixed cap 
that is not compromised by future growth;
    ? High compliance rates;
    ? Lower cost of compliance for individual sources and the 
regulated community as a whole;
    ? Incentives for early emissions reductions;
    ? Promotion of innovative compliance solutions and continued 
evolution of electricity generation and pollution control technology;
    ? Flexibility for the regulated community (without resorting 
to waivers, exemptions and other forms of administrative relief that 
can delay emissions reductions);
    ? Direct legal accountability by sources for compliance;
    ? Coordinated program implementation that efficiently 
applies administrative resources while enhancing compliance; and
    ? Transparent, complete, and accurate recording of emissions.
    These benefits result primarily from the interplay of a rigorous 
cap-and-trade framework, flexibility in compliance options, and the 
monetary incentives associated with avoided emissions in a market-based 
system. The model rules are designed around elements that are essential 
to a successful cap-and-trade program. These include:
    ? Simplicity (e.g., clear applicability thresholds, 
allocation formulas, trading rules and restrictions, measurement 
options and procedure, reporting requirements, and penalty assessment);
    ? Accountability (e.g., accurate measurement of emissions, 
complete and timely emission reporting, and automatic penalties for 
noncompliance);
    ? Transparency (e.g., full and open disclosure of 
programmatic elements, compliance data, allowance ownership, and 
environmental progress); and
    ? Predictability and Consistency (e.g., to provide 
consistent program implementation over time and a long compliance 
planning horizon that allows long-term, innovative strategies).
    States collectively benefit from the adoption of the model rules by 
improving the efficiency and clarity of the CAIR's implementation.
    In addition, States adopting the CAIR NO_X and 
SO₂ model rules will benefit from improvements to the rule 
mechanics that originated from the stakeholder input during the 
implementation of the Title IV, OTC, and NO_X SIP Call cap-
and-trade programs, as well as the EPA-managed ``lessons learned'' 
workshops held in 2003. Today's proposed NO_X and 
SO₂ model rules not only incorporate these refinements, but 
are designed to parallel the existing rules in parts 96 and 97 (see 
sections IV.A.4 and IV.B below) to allow States that have already 
codified all or part of these regulations to transition smoothly into 
both the CAIR NO_X and SO₂ programs.
2. Requirements for Adopting the Model Cap-and-Trade Rules
    Except as noted in section IV.A.3, States that choose to 
participate in the EPA-managed cap-and-trade programs must adopt the 
complete model cap-and-trade rules in order to participate in the 
program and to have it constitute an approvable remedy for achieving 
the mandated SO₂ and NO_X emission reductions. 
(Section III discusses the requirements for States, including those 
that wish to comply with the CAIR through alternatives other than the 
EGU-based emission reduction approach proposed in today's action.) This 
ensures that all participating sources, regardless of which State in 
the CAIR region they are located, are subject to the same rules. 
Further, requiring States to use the complete model rules provides for 
accurate and certain quantification of emissions, which are--when 
reflected in allowances--a valuable commodity on the trading market, 
and thereby maintains the financial integrity of the allowance trading 
market. In turn, the integrity of this emissions measurement system and 
the trading market ensures that the environmental goals are met.
    States are required to achieve all of the mandated emissions 
reductions from large EGUs if they wish to participate in the EPA-
managed cap-and-trade programs. (In other words, States that achieve 
all or part of the emissions reductions from large non-EGUs, may not 
participate in the EPA-managed cap-and-trade programs.) More 
specifically, the rules must apply to all fossil fuel-fired boilers and 
turbines serving an electrical generator with a nameplate capacity 
greater than 25MW and producing electricity for sale (except for 
certain cogeneration units). All units that meet this generation size 
threshold would be affected by the proposed CAIR with no exemptions for 
small, low-emitting units. (The EPA is not proposing an exemption for 
units that meet the generation applicability threshold but emit less 
than 25 tons of NO_X, as done in the NO_X SIP 
Call.) The EPA anticipates that these small, low-emitting units will 
take advantage of special monitoring and reporting procedures in part 
75 that simplify the requirements for low mass emitting (``LME'') 
units. In general, these procedures relieve much of the administrative 
burden and, therefore, compliance costs, for LME units by allowing them 
to use conservative emissions estimates in lieu of continuous emissions 
monitoring. In providing streamlined monitoring and reporting options, 
EPA can accurately and cost-effectively account for the emissions, even 
at low emission levels, and allow them to participate in the cap-and-
trade programs.
    Sources that produce usable thermal energy, such as steam, in 
addition to generating electricity are known as ``cogeneration units.'' 
Only a cogeneration unit that (i) serves a generator greater than 25 
MW, (ii) sells at least \1/3\ of its potential electrical output 
capacity and at least 25 MW of electricity, and (iii) meets certain 
operating and efficiency criteria is considered an EGU and covered by 
the EPA-managed cap-and-trade programs. (See section IV.B.1 for a 
proposed clarification to the definition of a cogeneration unit.)
    Once a unit is classified as an EGU for purposes of this rule, the 
unit will remain classified as an EGU regardless of any future 
modifications to the unit. If a unit serving a generator that initially 
does not qualify as an EGU (based on the nameplate capacity) is later 
modified to increase the capacity of the generator to the extent that 
the unit meets the definition of EGU, this unit will become an EGU for 
purposes of this rule. This approach is proposed to prevent avoidance 
of regulation by initially constructing units that are below the size 
threshold, and then upgrading above the size criteria.
3. Flexibility in Adopting the Model Cap-and-Trade Rules
    It is important to have consistency from State-to-State when 
implementing a multi-State cap-and-trade program to ensure that the 
intended emissions reductions are achieved and that the compliance and 
administrative costs are minimized. However, EPA believes that some 
differences, such as allowance allocation methodologies for 
NO_X allowances, are possible without jeopardizing the 
environmental goals of the program.
    a. Allocation of NO_X and SO₂ allowances. Each 
State participating in the EPA-managed cap-and-trade

[[Page 32710]]

programs must develop a method for allocating, or distributing, (to the 
extent that the State has allowances available to allocate) 
NO_X allowances equal to its CAIR EGU budget. For 
NO_X allowances, States have the flexibility to allocate 
their EGU NO_X budget to individual units however they 
choose. For SO₂, as noted in the approach outlined in the 
January 2004 proposal, States do not have discretion in their 
allocation approach since the proposal relies on title IV 
SO₂ allowances which have been already allocated in 
perpetuity to individual units by title IV of the CAA. Today's action 
proposes essential elements that would be required for each State's 
NO_X allocation method (e.g., the deadlines by which each 
State must complete and submit to EPA their unit-by-unit allocations 
for inclusion into the electronic data systems), describes areas in 
which States have flexibility, and provides an example allocation 
approach.
    i. Aspects unique to SO₂ allowance allocations. The CAIR 
SO₂ allocations differ from the NO_X approach 
because the title IV SO₂ allowances--the proposed basis for 
the CAIR--have already been allocated in perpetuity to specific units. 
Only units that were listed or described in the 1990 CAA Amendments are 
allocated allowances. Some units that are currently affected by the 
today's proposed rule title IV Acid Rain Program are not allocated 
title IV SO₂ allowances and instead must acquire all of the 
allowances they need in the marketplace.
    ii. Required aspects of a State allocation approach. While it is 
EPA's intent to provide States with as much flexibility as possible in 
developing allocation approaches, there are some aspects of State 
allocations that must be consistent for all States. Today's SNPR 
proposes that all State allocation systems are required to include 
specific provisions that establish when States notify EPA and sources 
of the unit-by-unit allocations. These provisions would create: (1) The 
minimum lead-time for a State to notify a source of its allocations; 
and (2) the deadline for each State to submit to EPA its unit-by-unit 
allocations for processing into the electronic data systems.
    Today's action proposes to require States to submit unit-by-unit 
allocations no less than 3 years prior to January 1 of the allowance 
vintage year. Requiring States to provide a minimum amount of 
notification ensures that an affected source--regardless of the State 
in the CAIR region in which the unit is located--would have sufficient 
time to plan for compliance. Finalizing allowance allocations less than 
3 years in advance of the compliance year may reduce a CAIR unit's 
ability to plan for compliance and, consequently, increase compliance 
costs. Shorter notification periods may also prevent CAIR units from 
participating in allowance futures markets, a mechanism for hedging 
risk and lowering costs. (Note: New units will not have allowances 3 
years in advance of their first year of operation.) In addition, States 
would be required to submit the unit-by-unit allocations to EPA by a 
specific date for sources in their State. This allows EPA to 
efficiently administer the program and ensure a fair and competitive 
market for allowances across the region.
    These minimum requirements would apply to the NO_X 
allocation approach and would not be relevant for SO₂, which 
relies on title IV allowances.
    iii. Flexibility and options for a state allowance allocations 
approach. Allowance allocation decisions in a cap-and-trade program are 
largely distributional issues, as economic forces would be expected to 
result in economically efficient and environmentally similar outcomes. 
Consequently, for CAIR NO_X allowances, States would be given 
latitude in developing their allocation approach. Allocation 
methodology elements for which States will have flexibility include:
    ? The cost of the allowance distribution (e.g., free 
distribution or auction);
    ? The frequency of allocations (e.g., permanent or 
periodically updated);
    ? The basis for distributing the allowances (e.g., actual 
heat-input or actual power output); and,
    ? The use of allowance set-asides (e.g., new unit set-asides 
or energy efficiency set-asides).
    These points are discussed immediately below.

Cost of Allowance Distribution

    Allowances may be distributed by either providing them at no cost 
(i.e., a ``free distribution''), offering them for sale to bidders 
(i.e., an ``auction''), or some combination of the two. Today's 
proposal allows the State to decide which approach is best for their 
circumstances.
    Auctions: In general, auctions ensure all parties, including the 
general public, have access to allowances and are considered to be 
economically efficient since sources would bid their perceived values 
for allowances. It is possible to auction all allowances under a cap, 
or have a hybrid approach that auctions some portion of the pool that 
could change over time. The title IV Acid Rain Program is an example of 
a hybrid in that it reserves 2.8 percent of available allowances for an 
auction and distributes the remainder for free. Auctions may also vary 
in the frequency with which they are held. Strict procedures must be 
established for auctions and, in the context of the proposed CAIR, 
States would be responsible for implementing these rules. Allowance 
auctions are typically, but are not required to be, open to any person, 
including sources or third-party entities, that can comply with the 
auction protocols. (In general, auction protocols establish key 
procedures for bidding, the bidding schedule, a bidding mechanism, and 
requirements for financial guarantees.)
    Auctions treat existing and new sources in a similar fashion. 
Sources performing costly retrofits to reduce emissions would then also 
have to pay for allowances for their remaining emissions. Some other 
benefits of auctions include the fact that they eliminate the permanent 
right to emit and can provide distortion-free revenues to States.
    Free Distribution: A free distribution system provides allowances 
to any entity, typically the affected sources, as determined by the 
State. When using a free distribution, it is necessary to establish 
both (1) the basis for determining each unit's share of the allowance 
pool, and (2) the frequency with which the allowances are allocated. 
The title IV Acid Rain Program is an example of a free, one-time 
distribution (with a small percentage reserved for auction, as 
mentioned above) that uses the product of historical heat input and 
specified emission rates (i.e., a permanent, heat input-based system) 
to determine each unit's share of the pool.
    Allocating allowances for free could lessen the financial impact of 
the program on the affected sources which already bear the compliance 
costs, but would not be expected to affect the sources' output 
decisions, or labor and pricing decisions. It would also give States 
the ability to determine the initial allowance recipients.

Frequency of Allocating Allowances

    Allowances may be allocated once (i.e., a ``permanent'' allocation) 
or periodically recalculated (i.e., ``updated'') based upon some 
protocol. When deciding upon the frequency of the allocations, any of 
the options concerning the cost of distribution and the basis for 
apportioning the pool may be used. However, it is important to consider 
the practical implications of using complex protocols, such as data 
that must undergo time-consuming

[[Page 32711]]

quality assurance, when frequently updating.
    Permanent Systems: Permanent systems allocate all of the allowances 
at the beginning of the program. They provide long planning horizons 
for affected sources that receive an allocation.
    Permanent allocations do not create additional incentives for those 
units that receive allowances to change their future behavior to garner 
more allowances (e.g., increase utilization). Furthermore, because 
permanent systems are based on a historic baseline, they would not 
reflect changes in the industry going forward. For instance, retired 
units would continue receiving allowances. Additionally, a pure 
permanent allocation system would not provide for allowances to new 
affected units that begin operations after the allocation of allowances 
and instead would require them to obtain allowances from the market. 
The title IV Acid Rain Program is an example of a primarily permanent 
approach that auctioned 2.8 percent of the allowances to provide new 
sources an additional mechanism for obtaining allowances.
    Updating Systems: Updating systems periodically recalculate and 
reallocate allowances. These include: The ability to reflect future 
changes in the power sector; the ability to impact the future 
generation mix; and, an inherent mechanism for new generators to gain 
access to free allowances. An updating system that bases the allowance 
distribution on power output provides an additional incentive beyond 
the inherent reward for efficiency provided by the market for existing 
units to improve their generation efficiency and for new units to 
employ the most efficient technology available.
    Updating methods may provide a slight subsidy for units to either 
generate (for output-based systems) or consume more fuel (for input-
based systems). Should this potential subsidy result in an increase in 
electricity production, there would be a corresponding slight 
distortion (lowering) of the price of electricity as well as an 
incentive for older units to continue generating. (Note that under a 
capped program, incentives to generate will not impact the total 
emissions of the capped pollutants.)
    There are additional aspects of the allocation frequency that are 
significant in an updating system. These include:
    ? The length of the period for which allocations are 
determined (e.g., the allocations may be calculated for one year or for 
5 years at a time); and
    ? The length of the notification time (e.g., allocations are 
determined and announced 3 years into the future, 5 years into the 
future).
    In general, the longer the allocation period (i.e., the less 
frequent the updating), the more the system will resemble a permanent 
approach.

Allowance Set-Asides

    Allocation methodologies may include a reserve of a certain number 
allowances from within the cap to create a ``set-aside'' of allowances. 
This reduces the number of allowances available to the existing 
affected sources. Set-asides may be used for a variety of purposes 
including encouraging certain behaviors (e.g., demand-side energy 
efficiency and renewable energy set-asides) and mitigating potential 
disadvantages in the marketplace (e.g., auction set-asides or, as 
discussed below, set-asides available to units that come online after 
the program implementation date). In the context of the proposed CAIR, 
States (if they choose to have set-asides) would be responsible for 
developing and implementing protocols to distribute set-asides. Set-
asides may have provisions that distribute unused allowances back to 
affected sources should the set-asides not be fully utilized.
    New unit set-asides create a pool of allowances that are available 
to units that come online after the allowances have been allocated. 
This may mitigate potential barriers to entering the market for new 
units. Should a new unit be included in an allocation approach, it is 
necessary to determine how the allowances will be distributed to the 
new units from the pool. Common approaches include basing each unit's 
share on either heat input or power output. Depending upon the type of 
performance measurement used, slightly different incentives may be 
created. For example, if the new unit's power output were used to 
distribute the set-aside, sources would find an additional incentive--
beyond the incentive for efficiency inherent in the market--to employ 
more efficient generation technology. (Note that the allocation example 
provided below includes a new unit set-aside with a hybrid input/output 
distribution metric.)

Basis for Determining Share of Allowance Pool

    For any allocation option, other than an allowance auction, it is 
necessary to establish the primary parameter that will be used to 
determine each unit's share of the allowance pool. This parameter is 
typically a performance measure such as:

? Measured or potential emissions (in tons ) from the unit;
? Historical or current measured heat input (in mmBtu) of the unit; or
? Measured or potential production output (in terms of 
electricity generation and/or steam energy) of the unit.

    Any of these parameters may be used to distribute allowances, 
regardless of whether it is a permanent or updated system. Other 
factors, such as fuel type or emission rates (e.g., pounds of pollutant 
per mmBtu heat input or pounds of pollutant per MWhr of power output) 
may be used with the above parameters. As mentioned earlier in this 
discussion of allocation options, the choice of the parameter for 
distributing allowances can influence the behavior of affected sources 
in an updating system.
    iv. Example allowance allocation system. Included below is an 
example (offered for informational guidance) of an allocation 
methodology that includes allowances for new generation and is 
administratively straightforward. The method involves input-based 
allocations for existing fossil units, with updating to take into 
account new generation on a modified output basis. This methodology is 
offered as an example, as individual States would make their own choice 
regarding what type of allocation method to adopt for NO_X 
allowances.
    Initial allocations for existing sources could be made for the 
first control periods at the start of the program on the basis of heat 
input. After the first 5 years, the budget would be distributed on an 
annual basis, taking into account data from new units.
    As new units enter into service and establish a baseline, they 
begin to pick up allowances in proportion to their share of the 
generation. Allowances allocated to existing plants slowly decline as 
their share of total heat input decreases with the entry of new plants. 
In this EPA example methodology, existing units as a group would not 
update their heat input. This would eliminate the potential for a 
generation subsidy (and efficiency loss) as well as any potential 
incentive for less efficient units to generate more. This methodology 
would also be easier to implement since it would not require the 
updating of existing units' baseline data. Retired units would continue 
to receive allowances indefinitely, thereby creating an incentive to 
retire less efficient units.
    Through this EPA example methodology, new units as a group would 
only update their heat input

[[Page 32712]]

numbers once--in the initial baseline period when they start operating. 
This would eliminate any potential generation subsidy and be easier to 
implement, since it would not require the collection and processing of 
data needed for regular updating.
    The EPA believes that allocating based on heat input data (rather 
than output data) for existing units is desirable because accurate 
protocols exist for monitoring this data and reporting it to EPA, and 
several years of certified data are available for most of the affected 
sources. This heat input data for existing units could be adjusted by 
multiplying it by different factors based on fuel-type, reflecting the 
inherent higher emissions of coal-fired plants. For example, factors 
could be calculated based on average historic NO_X emissions 
rates by fuel type (i.e., coal, gas and oil) throughout the proposed 
CAIR region for the years 1999-2002 at 1.0 for coal, 0.4 for gas and 
0.6 for oil.
    However, allocating on the basis of input for new sources would 
serve to subsidize less-efficient new generation. For a given 
generation capacity, the most efficient unit would have the lowest fuel 
input or heat input. Allocating to new units based on heat input may 
encourage the building of less efficient units since they would get 
more allowances than an efficient, lower heat input unit. The modified 
output approach, as described below, would encourage new, clean 
generation and would not reward inefficient or higher emitting new units.
    Allowances would be allocated to new units on a ``modified output'' 
basis. The new unit's modified output would be calculated by 
multiplying its gross output by a heat rate conversion factor of 8,000 
btu/kWh. The 8,000 btu/kWh value for the conversion factor is a mid-
point between expected heat-rates for new gas-fired combined cycle 
plants, new pulverized coal plants, and new IGCC coal plants (based 
upon assumptions in EPA's economic modeling analysis. See documentation 
for IPM at http://www.epa.gov/airmarkets/epa-ipm/attachment-h.pdf). 
In addition, this would create consistent incentives for efficient 
generation (rather than favoring new units with higher heat-rates). For 
new cogeneration units, their share of the allowances would be 
calculated by multiplying (1) the sum of their electric output and one 
half of their equivalent electrical output energy for the unit's 
process steam, times (2) 8,000 btu/kWh conversion factor.
    Five years after entering the CAIR cap-and-trade programs, new 
units would be incorporated into the calculations for allocations to 
all affected units. After 5 years of participating in the cap-and-trade 
programs, new units would have an adequate operating baseline of heat 
input data. The average of the highest 3 years from these 5 years would 
be used to calculate the heat input value that the new unit would use 
to receive allowances from the pool of allowances for all sources.
    In this example, only fossil units would be included in the 
updating process. This is administratively more straightforward and 
would comprise the vast majority of expected new generation. 
Alternately, all new generating units could be included in the updating 
process, which would provide incentives for all new generation (such as 
renewables, hydro, nuclear). To include such non-fossil units as part 
of the program would involve clearly defining the entities which could 
participate (e.g., application procedures, size requirements, and 
boundaries of included generation, since there is no clear analog to 
discrete fossil ``units'').
    New units that have entered service, but have not yet established a 
baseline output and have not yet started receiving allowances through 
the update, could receive allowances each year from a new source set-
aside. In this example methodology, EPA has described a new source set-
aside representing 2 percent of the State's emission budget.
    Allowances in the new source set-aside could be distributed in a 
number of different ways. For example, as described in today's proposed 
model rules, the new source allowances could be distributed based on a 
unit's utilization/output and the unit's NSPS rate limitation as 
proposed in the Clear Skies Act of 2003. Because the proposed NSPS 
rates vary across fuel types, this allocation method could provide new 
plant investors with varying incentives depending upon the fuel type. 
While this set-aside would help new sources relative to a situation 
with no set-aside, because the demand for allowances for future sources 
is unknown, it is difficult to know beforehand what should be the 
appropriate size of the set-aside pool.
    Another potential approach for distributing allowances from a new 
source set-aside is using a single emissions rate for all new plants 
and a plant specific utilization or power output level to calculate 
allowance allocations for new units before they begin receiving 
allowances through the update. Alternatively, the lower of the NSPS 
rates for the respective fuel types and a rate representing the 
proposed caps in 2010 and 2015 divided by projected 2010 and 2015 total 
affected unit generation may be used to calculate allowance allocations 
for new units before they begin receiving allowances through the 
update. This alternative would ensure that new sources would receive 
allowances at the same rate as that applied to existing sources and no 
greater than their proposed NSPS. A State may also choose to distribute 
allowances from this set-aside through an auction, which could be open 
to anyone or limited (e.g., only new sources could participate). We ask 
for comment on these various proposals, and for any other alternatives 
commenters may wish to raise.
    In today's proposed example allocation methodology, new units would 
begin receiving allowances from the set-aside for the control period 
immediately following the control period in which the new unit 
commenced commercial operation, based on the unit's actual utilization 
rates for the preceding control period. States would allocate 
allowances from the set-aside to all new units in any given year as a 
group. If there were more allowances requested than in the set-aside, 
allowances would be distributed on a pro rata basis. Allowance 
allocations in following years would continue to be based on the prior 
year's utilization until the new unit is considered an existing unit 
and is allocated allowances through the State's updating process. This 
would enable new units to have a good sense of the amount of allowances 
they would likely receive--in proportion to their generation. This 
methodology would not provide allowances to a unit in its first year of 
operation; however this methodology is straightforward and predictable.
    As an alternative, States could distribute a new source set-aside 
for a control period based on full utilization rates. Then, at the end 
of the year, the actual allowance allocation would be adjusted to 
account for actual unit utilization/output, and excess allowances would 
be returned and redistributed, first taking into account new unit 
requests that were not able to be addressed. This was the example 
methodology used in the NO_X SIP Call model rule. In 
implementing the NO_X SIP Call, EPA found this approach to be 
complicated for both the States and the Agency in implementing the 
procedure, as well as to the sources as this approach introduces a 
higher level of uncertainty in the allocation process than may be 
necessary.

[[Page 32713]]

    With either approach, any unused set-aside allowances could be 
redistributed to existing units based on their existing allocations. 
The EPA is soliciting comment on the timing and method of allocating 
allowances from the set aside in the example methodology.
    While EPA recognizes States' flexibility in choosing their 
NO_X allocations method and is proposing that States be 
allowed to determine their own method for allocating allowances to 
sources in their State, EPA is also asking for comment on all aspects 
of this example allocation proposal and whether the proposed regulatory 
language, which codifies the above example as proposed in today's SNPR, 
could reflect a different approach.
    The EPA is also soliciting comment on alternate allocation methods.
    b. Individual unit opt-in. In today's SNPR, EPA is soliciting 
comment on whether opt-in provisions (i.e., provisions that allow units 
that otherwise would not be subject to the proposed CAIR to 
individually elect, or ``opt,'' to participate in the proposed CAIR 
cap-and-trade programs) should be included in the final CAIR rule. 
Further, EPA provides and solicits comment on an example opt-in 
approach that could be included in the final CAIR model rules. If opt-
in provisions are included in final model rules, States would not be 
required to include them, and both States with and without opt-in 
provisions could participate in the EPA-managed cap-and-trade programs. 
States that chose to include opt-ins would be required to adopt EPA's 
methodology for including opt-ins as is.

Description of Potential Opt-In Approach

    Opt-ins would be restricted to boilers and turbines that (1) 
exhaust to a stack or duct, and (2) meet the same monitoring and 
reporting requirements as CAIR-affected units. These requirements 
ensure the consistent, rigorous monitoring and reporting required to 
maintain the integrity of the emissions cap and trading market. To 
establish baseline emissions and operating information, opt-in units 
would be required to monitor and report in accordance with part 75 for 
a minimum of one full calendar year prior to the unit entering the CAIR 
trading program. If 3 or more consecutive calendar years of part 75 
quality assured emissions and heat input data are available, then an 
average of the most recent 3 calendar years would be used to establish 
the baselines.
    If a unit chooses to opt-in, the unit is required to opt into both 
the SO₂ and NO_X cap-and-trade programs. By 
requiring units to opt-in for both SO₂ and NO_X, 
opt-in units are encouraged to develop integrated control strategies. 
In addition, the burden of including opt-in units in the cap-and-trade 
programs could be somewhat offset by the benefit of both SO₂ 
and NO_X emission reductions.
    Opt-in units would be allocated SO₂ and NO_X 
allowances on a year-by-year basis. The annual updating of allocations 
based upon utilization reduces concerns that individual opt-in units 
may shift utilization and, therefore, emissions, to other, unaffected 
units. Opt-in allocations would be based upon (1) an emission rate, and 
(2) the lesser of the baseline heat-input or the actual heat input 
measured at the unit for the prior year. For example, the potential 
SO₂ allocation for an opt-in unit could be calculated by 
taking (i) the lesser of the unit's actual heat-input for the prior 
year or the unit's annual average baseline heat input for the most 
recent 3 years for which part 75 quality-assured data are available 
(or, if 3 years of such data are not available, the one year prior to 
opting into the CAIR programs) and multiplying it by (ii) the lesser of 
the unit's baseline SO₂ emissions rate, the most stringent 
State or Federal SO₂ emissions limitation that applies to 
the unit during the calender year prior to the year in which the unit 
is being allocated allowances, or the emission rate representing 50 
percent of the unit's baseline SO₂ emission rate (in lb/
mmBtu)for the years 2010 through 2014 and 35 percent of the units's 
baseline SO₂ emission rate (in lb/mmBtu) for 2015 and 
beyond. The EPA takes comment on this approach and specifically 
solicits comment on allocating to opt-in units at a range of 20 to 65 
percent below their baseline SO₂ emission rates--the 
equivalent of multiplying the baseline emission rate in the above 
equation by 80 to 35 percent of their baseline emissions, respectively. 
The NO_X allocation for an opt-in unit could be calculated by 
taking (i) the lesser of the unit's actual heat-input for the prior 
year or the unit's annual average baseline heat input for the most 
recent 3 years for which part 75 quality assured data is available or, 
if 3 years of such data are not available, the one year prior to opting 
into the CAIR program and multiplying it by (ii) the lesser of the 
unit's baseline NO_X emission rate, the most stringent State 
or Federal NO_X emissions limitation that applies to the opt-
in unit at any time during the calendar year prior to opting into the 
CAIR program, or 0.15 lb/mmBtu for the years 2010 through 2014, and 
0.11 lb/mmBtu for the years 2015 and beyond (these rates are based on 
the average emission rates at which EPA projects EGUs will be 
emitting). The EPA is taking comment on this approach and specifically 
solicits comment on allocating to opt-in units at a range of levels 
that are 20 to 65 percent below their baseline NO_X 
emissions, where an emissions rate of 0.11 lb NO_X/mmBtu is 
roughly equivalent to a 65 percent reduction.
    States would need to notify EPA after the end of the calendar year 
in order to allocate SO₂ and NO_X allowances to an 
opt-in unit for the next calendar year. Because opt-in allocations 
would be based upon data developed for the previous year, the 
allocations would be distributed a few months after the beginning of 
the next year (e.g., by April 1 of the next year, which would be of the 
year for which the allowances are needed for compliance).
    Non-EGU boilers and turbines under the NO_X SIP Call that 
choose to opt-in to the CAIR cap-and-trade programs would still be 
required to meet the NO_X SIP Call seasonal NO_X 
limitations. (The EPA does not have modeling, similar to that for EGUs, 
that projects that if non-EGUs meet the annual NO_X emission 
limits, they will also meet the ozone season NO_X emission 
limit as well.) This requirement would ensure that the NO_X 
SIP Call States continue to meet their summertime NO_X 
emission limits and make progress toward attaining the ozone NAAQS.
    Opt-in units must remain in the CAIR program for at least 5 years. 
This would improve the cost effectiveness of implementing the program 
and would avoid potential incentives for opting in and out of the 
program. An opt-in unit could withdraw from the CAIR program any time 
with the request being effective on December 31 following the 
submission of the request or a subsequent December 31. The EPA believes 
that the administrative burden for a permitting authority in processing 
a withdrawal effective during a calendar year--particularly in 
ascertaining the disposition of SO₂ and NO_X 
allowances and in determining compliance for a partial calendar year--
would be sufficient to warrant the prohibition of an effective date of 
withdrawal during a calendar year. Further, EPA believes that an opt-in 
unit should not be allowed to withdraw retroactively, whether during a 
calendar year or at the end of a prior calendar year. The ability to 
withdraw retroactively could reduce the incentive to comply since an 
opt-in unit could simply withdraw once it projects that it will not 
hold enough SO₂

[[Page 32714]]

and/or NO_X allowances to account for its SO₂ and/
or NO_X emissions for that calendar year. At best, under such 
a scenario, there would be no benefit from allowing the opt-in of the 
unit. Under an alternate scenario, allowing the unit to ``opt out'' of 
the program during a calendar year could result in higher overall 
SO₂ and/or NO_X emissions, since an opt-in unit 
could reduce its emissions during part of the year, sell some of its 
allowances, and increase its emissions after withdrawing from the 
program. Such increased emissions would not be accounted for with the 
requisite surrender of SO₂ and/or NO_X allowances 
required under the CAIR cap-and-trade programs and could occur outside 
of a State's annual budget for SO₂ and/or NO_X. 
The opt-in unit could, in effect, shift utilization from the part of 
the year for which it must surrender allowances for emissions to the 
part of the year for which emissions do not require an allowance 
surrender.
    Opt-in permits would be terminated for any unit that becomes a 
CAIR-affected unit. This change in regulatory status for an opt-in unit 
could occur as a result of a modification or reconstruction that may 
take place at the unit. An opt-in unit that becomes a CAIR-affected 
unit would be required to notify the permitting authority within 30 
days of the change in regulatory status. The permitting authority 
should revise the opt-in permit to reflect the CAIR permit content 
requirements of subparts CC and CCC (for NO_X and 
SO₂, respectively), effective as of the date of the change 
in status. The SO₂ and NO_X allowances would be 
deducted or allocated as necessary to ensure that the appropriate 
number of allowances are allocated to the unit consistent with the 
proposed CAIR trading rules for each calendar year after the effective 
date of the change in status.
4. Structure of Proposed CAIR Model Trading Rules
    In order to make the proposed CAIR NO_X and 
SO₂ model trading rules as simple and consistent as 
possible, EPA designed them to parallel the model trading rules of the 
NO_X SIP Call (part 96) and the Federal NO_X Budget 
Trading Program (part 97). Because EPA is proposing new CAIR 
NO_X and SO₂ model rules--separate from the 
existing model rule in part 96--States can continue to reference part 
96 as they implement the NO_X SIP Call through 2009. The new 
CAIR NO_X and SO₂ model rules use the same basic 
structure as part 96 and will allow for an easier transition to the 
CAIR rules as States and sources will already be familiar with the rule 
layout. Specifically, the model rules will be codified as follows:

    ? NO_X SIP Call model cap-and-trade rule will 
remain in part 96 subparts A through J;
    ? CAIR NO_X model cap-and-trade rule will be 
created in part 96 subparts AA through HH;
    ? CAIR SO₂ model cap-and-trade rule will be 
created in part 96 subparts AAA through HHH; In addition, today's SNPR 
will add and reserve subparts between those proposed in today's action 
(i.e., subparts K through Z, subparts II through ZZ, and subparts III 
through ZZZ). Both the CAIR NO_X and SO₂ model 
rules will rely upon the detailed unit-level emissions monitoring and 
reporting procedures of part 75. (Note that proposed regulations 
establishing SIP requirements under the CAIR, i.e., part 51, are 
discussed in section III of today's action.) Additionally, section III 
of today's SNPR proposes revisions to part 72 through 77 in order to, 
among other things, harmonize the title IV Acid Rain Program's 
SO₂ cap-and-trade provisions with those of the proposed CAIR.

B. Elements of the Proposed NO_X and SO₂ Model 
Trading Rules, Subparts AA Through HH and AAA Through HHH

    This section of today's SNPR describes the purpose of each subpart 
of the proposed NO_X and SO₂ model trading rules 
in parallel. The descriptions highlight any improvements relative to 
corresponding sections in the existing part 96 (NO_X SIP 
Call) and part 97 (Federal NO_X Budget Trading Program) model 
rules. In addition, each subsection notes provisions that have been 
specifically adapted for either the CAIR SO₂ or 
NO_X trading program.
1. Subparts AA and AAA, CAIR NO_X and SO₂ Trading 
Program Applicability and General Provisions
    a. 96.101 and 96.201 purpose. This section states the reason for 
the regulation.
    b. 96.102 and 202 Definitions and 96.103 and 96.203 measurements, 
abbreviations, and acronyms. Many of the definitions, measurements, 
abbreviations, and acronyms remain unchanged from those used in 40 CFR 
parts 96 and 97, in order to maintain consistency among programs. 
However, certain terms that are specific to the CAIR SO₂ and 
NO_X model cap-and-trade rule have been added and certain 
other terms have been modified.
    In today's supplemental proposal of the model SO₂ cap-
and-trade rule, EPA has defined CAIR SO₂ allowances to 
reflect the SO₂ retirement ratios described in section 
VIII.B.2.f (69 FR 6932) of the January 2004 proposal. Specifically, the 
definition established the number of title IV or CAIR SO₂ 
allowances, by vintage, that must be retired to offset one ton of 
SO₂ emissions. Specifically, one SO₂ allowance of 
vintage years 2009 and earlier authorizes the emission of one ton of 
SO₂. Two SO₂ allowances of vintage years 2010-
2014 authorize one ton of SO₂ emission. Three SO₂ 
allowances of vintage years 2015 and beyond authorizes the emission of 
one ton of SO₂.
    In today's SNPR, EPA is clarifying the definition of cogeneration 
unit included in the January 2004 proposal. (This clarification also 
corrects an error in the January 2004 proposal, where it was 
erroneously stated that the definition of a cogeneration facility under 
the title IV Acid Rain Program and the NO_X SIP Call was 
based on the Federal Energy Regulatory Commission's qualifying 
cogeneration facility definition.) The EPA proposes to use a definition 
of cogeneration unit that is based on the Acid Rain Program definition 
of ``cogeneration unit'' and the Federal Energy Regulatory Commission's 
(FERC) definitions of ``cogeneration unit'' and ``qualifying 
cogeneration facility.'' The proposed ``cogeneration unit'' has two 
elements. First, in order to be a ``cogeneration unit,'' a unit must 
produce electric energy and useful thermal energy for industrial, 
commercial, heating or cooling purposes, through the sequential use of 
original fuel energy. See 40 CFR 72.2 and 18 CFR 292.202(c) 
(``cogeneration'' definition). Second, the unit must meet the operating 
and efficiency standards under 18 CFR 292.205, but applied to all 
cogeneration units, instead of applying the efficiency standards only 
to oil- and gas-fired units as under 18 CFR 292.205. The EPA believes 
that applying the operating and efficiency standards to all units would 
be more consistent with its fuel-neutral approach throughout this 
proposed rule. In addition, not applying the efficiency standards to 
coal-fired units would be counter-productive to EPA's efforts to reduce 
SO₂ and NO_X emissions under this proposed rule 
because of the relatively high SO₂ and NO_X 
emissions from coal-fired units. Thus, under the second element of 
today's proposed ``cogeneration unit'' definition, a topping-cycle 
cogeneration unit must meet the following requirements.
    The useful thermal energy output of the unit must be no less than 5 
percent of the total energy output during the 12-month period beginning 
with the date the unit first produces electric energy

[[Page 32715]]

and any subsequent calendar year. The useful power output of the unit 
plus one-half the useful thermal energy output, during the 12-month 
period beginning with the date the unit first produces electric energy, 
and any calendar year after the year in which the unit first produces 
electric energy, must be: (i) No less than 42.5 percent of the total 
energy input to the unit; or (ii) if the useful thermal energy output 
is less than 15 percent of the total energy output of the unit, no less 
than 45 percent of the total energy input to the unit.
    For bottoming-cycle cogeneration units, the useful power output of 
the unit during the 12-month period beginning with the date the unit 
first produces electric energy, and any subsequent calendar, must be no 
less than 45 percent of the energy input.
    c. 96.104 and 204 Applicability. Today's SNPR proposes to affect 
fossil fuel-fired boilers and turbines serving an electrical generator 
with a nameplate capacity exceeding 25MW and producing power for sale. 
Cogeneration units would be affected if they meet the definition in b. 
above.
    d. 96.105 and 205 Retired unit exemption. This section of today's 
SNPR provides an exemption from the CAIR NO_X and 
SO₂ trading program requirements for retired units so that 
retired CAIR units will be free from unnecessary requirements (e.g., 
emissions monitoring and reporting). The EPA proposes an exemption 
beginning on the day the unit permanently retires, requiring no notice 
and comment period regarding the retirement. This provision proposes 
that the CAIR Designated Representative (CAIR DR) (i.e., the person 
authorized by the owners and operators to make submissions and handle 
other matters) submit notification to the permitting authority of the 
CAIR unit's retirement within 30 days of the cessation of activity. 
(Note that the CAIR DR designation is similar to the title IV Acid Rain 
Program's Designated Representative, or ``Acid Rain DR,'' and the 
NO_X SIP Call's Authorized Account Representative, or 
``AAR.'') In response, the permitting authority would amend the 
operating permit in accordance with the exemption and notify EPA of the 
unit's status as exempt. This provision imposes conditions that all 
program requirements prior to the exemption are fulfilled and records 
are kept on site to verify the non-emitting status of the retired unit. 
A retired unit could continue to hold NO_X and SO₂ 
allowances previously allocated or be allocated NO_X and 
SO₂ allowances in the future depending on the allocation 
provisions adopted by the State where the retired unit is located. The 
number of future year NO_X and SO₂ allowances that 
a retired unit would be allocated would be dependent on the given 
State's allocation system. The NO_X and SO₂ 
allowance allocations are discussed in sections IV.A.3.a and IV.B.5 of 
this SNPR.
    In order to resume operation without violating program requirements 
(i.e., an exemption requires that the unit's permit language be changed 
to reflect that it would not emit any NO_X and SO₂ 
emissions), the CAIR DR must submit a permit application to the 
permitting authority no less than 18 months (or less, if so specified 
by the applicable State permitting regulations) prior to the date on 
which the unit is to resume operation, to allow the permitting 
authority time to review and approve the application for the unit's re-
entry into the program. If a retired unit resumes operation, EPA 
proposes to automatically terminate the exemption under this part.
    e. 96.106 and 96.206 Standard requirements. Today's SNPR delineates 
the standard requirements that CAIR units and their owners, operators, 
and CAIR DRs must meet under the CAIR NO_X and SO₂ 
cap-and-trade program. This provision sets forth references to other 
portions of the cap-and-trade rule for the full range of program 
requirements: Permits, monitoring, NO_X and SO₂ 
emissions limitations, excess emissions, recordkeeping and reporting, 
liability, and effect on other authorities. For example, the 
permitting, monitoring, and emissions limit requirements are discussed 
in general and the relevant sections of the cap-and-trade rule are 
cited. The liability provisions state that the requirements of the 
trading program must be met, and any knowing violations or false 
statements are subject to enforcement under the applicable State or 
Federal law. Violations and the associated liability are established on 
a facility-wide basis. The provision addressing the effect on other 
authorities establishes that no provision of the trading program can be 
construed to exempt the owners or operators of a CAIR source from 
compliance with any other provision of the applicable SIP, any 
federally enforceable permit, or the CAA. This provision ensures, for 
example, that a State may set a binding source-specific NO_X 
and SO₂ limitation and, regardless of how many allowances a 
CAIR source holds under the trading program, the emissions limit 
established in the SIP cannot be violated.
    Automatic penalties for non-compliance have been key to the success 
of the title IV and the NO_X SIP Call's cap-and-trade 
programs and are an important feature of the proposed CAIR model rules 
as well. Simple, transparent, automatic penalties avoid litigation, 
which can be costly for both the air authorities and the sources, for 
most non-compliance instances. For severe non-compliance, the air 
authorities retain the right to pursue civil actions.
    f. 96.107 and 207 Computation of time. This section clarifies how 
to determine the deadlines referenced in the proposal. For example, 
deadlines falling on a weekend or holiday are extended to the next 
business day. These are the same computation-of-time provisions as are 
in the regulation for the title IV and the NO_X SIP Call 
emissions trading programs.
2. Subparts BB and BBB, CAIR Designated Representative for CAIR Sources
    Sections 96.108 and 96.208 of today's SNPR establish procedures for 
appealing the decisions of the Administrator regarding the model cap-
and-trade rules in part 78. Part 78 also includes administrative appeal 
procedures for the Acid Rain Program and the Federal NO_X 
Budget Trading Program. Today's SNPR revises part 78 to make these 
procedures applicable to the CAIR NO_X and SO₂ 
trading programs as well.
    Sections 96.110 through 96.114 and 96.210 and 96.214 of today's 
proposed CAIR NO_X and SO₂ cap-and-trade programs 
rule establish the process for certifying the CAIR DR and describe his 
or her duties. Patterned after the roles and responsibilities of the 
title IV Acid Rain Program's DR, a CAIR DR is the individual authorized 
to represent the owners and operators of each CAIR NO_X and 
SO₂ unit at a CAIR source (i.e., a facility that includes at 
least one CAIR affected unit) in matters pertaining to the CAIR cap-
and-trade programs. Because the CAIR DR represents the owners and 
operators of all the CAIR NO_X and SO₂ units at a 
CAIR source, the CAIR DR must certify that he or she was selected by an 
agreement binding on all such owners and operators and is authorized to 
act on their behalf. The CAIR DR's responsibilities include: The 
submission of permit applications to the permitting authority, 
submission of monitoring plans and certification applications, holding 
and transferring CAIR allowances, and submission of emissions data. The 
rule proposes that each CAIR source have one DR that is responsible for 
both the NO_X and SO₂ cap-and-trade program 
requirements. Additionally, the rule proposes to

[[Page 32716]]

require that the CAIR DR be the same individual as the title IV Acid 
Rain Program's Designated Representative (Acid Rain DR) at each source. 
These requirements will ensure that one individual is responsible for 
all matters pertaining to the CAIR as well as significantly reduce the 
burden on the data systems used in the administration of the cap-and-
trade programs.
    The EPA recognizes that the CAIR DR cannot always be available to 
perform his or her duties. Therefore, the rule proposes to allow for 
the appointment of one alternate CAIR DR for a CAIR source. The 
alternate CAIR DR would have the same authority and responsibilities as 
the CAIR DR. Therefore, unless expressly provided to the contrary, 
whenever the term ``CAIR Designated Representative'' is used in the 
rule, it should be read to apply to the alternate CAIR DR as well. 
While the alternate CAIR DR would have full authority to act on behalf 
of the CAIR DR, all correspondence from EPA, including reports, would 
be sent only to the CAIR DR. It should be noted that additional 
flexibility is provided within the electronic data systems that EPA 
uses to administer the program. Within these systems the CAIR DR may 
assign ``agents'' to perform specific tasks on his or her behalf, such 
as submission of allowance transfers and electronic data reports.
    Today's SNPR requires the completion and submission of the 
Certificate of Representation in order to certify a CAIR DR for a CAIR 
source and all CAIR NO_X and SO₂ units at the 
source. There would be one standard form (the Certificate of 
Representation [DR form]) which would be submitted by sources to EPA. 
The DR form would include identifying information for the source, the 
CAIR DR and the alternate CAIR DR, if applicable; the name of every 
owner and operator of the source and each CAIR unit at the source; and 
certification language and signature of the CAIR DR and alternate, if 
applicable. The EPA would design this form to also include the Acid 
Rain DR certifications, and the CAIR DR would indicate which units at 
the source are included in which programs. This form can also be 
completed and submitted electronically. Upon receipt of a complete DR 
form, EPA would establish a compliance account for each source in the 
systems used to track SO₂ and NO_X allowances.
    In order to change the CAIR DR, alternate CAIR DR, or list of 
owners and operators, EPA is proposing that a new complete account 
certificate of representation be submitted. The EPA believes the CAIR 
DR requirements afford the regulated community with flexibility, while 
ensuring source accountability and simplifying the administration of 
the cap-and-trade program.
3. Subparts CC and CCC, CAIR Permits
    a. 96.120 and 96.220 General CAIR NO_X and SO₂ 
trading program permit requirements. The EPA has attempted to minimize 
the number of new procedural requirements for CAIR permitting and to 
defer, whenever possible, to the permitting programs already 
established by the permitting authority. The proposed CAIR trading 
program regulations assume that the CAIR permit would be a portion of a 
federally enforceable permit issued to the CAIR source and administered 
through permitting vehicles such as operating permits programs 
established under title V of the CAA and 40 CFR part 70. Generally, the 
permits regulations promulgated by the permitting authority cover: 
Permit application, permit application shield, permit duration, permit 
shield, permit issuance, permit revision and reopening, public 
participation, and State and EPA review. The proposed CAIR trading 
program permit regulations generally require use of the procedures 
under these other regulations and add some requirements such as CAIR 
permit application submission and renewal deadlines, CAIR permit 
application information requirements and permit content, and the term 
``CAIR permit''. The term ``CAIR permit'' throughout this preamble and 
the CAIR trading program regulations therefore refers to the CAIR 
trading program portion of the permit issued by the permitting 
authority to a CAIR source.
    b. 96.121 and 96.221 Submission requirements for CAIR 
NO_X and SO₂ permit applications. The proposed 
rule sets the initial CAIR permit application deadlines for units in 
operation before January 1, 2007 so that the permits will be issued by 
January 1, 2010. January 1, 2010 is the beginning of the first control 
period for the CAIR cap-and-trade program, and therefore also the date 
by which initial CAIR permits for existing units should be effective. 
Application submission deadlines are based on the permitting 
authority's title V permitting regulations. For instance, if a 
permitting authority's permitting regulations allowed 12 months for 
final action by the permitting authority on a permit application, the 
application deadline would be the later of January 1, 2009 (12 months 
prior to January 1, 2010) or 12 months before the unit commences 
operation. The same principle applies to CAIR units commencing 
operation on or after January 1, 2007, except that the application 
submission deadline is the later of the date the CAIR unit commences 
operation or January 1, 2010. The CAIR permit renewal application 
deadlines are the same as those that apply to permit renewal 
applications in general for sources under Title V. For instance, if a 
permitting authority requires submission of a Title V permit renewal 
application by a date which is 12 months in advance of a title V 
permit's expiration, the same date would also apply to the CAIR permit 
application.
    c. Sections 96.122 and 96.222, Information requirements for CAIR 
permit applications and Sec. Sec.  96.123 and 96.223 CAIR permit 
contents and term. The CAIR cap-and-trade program requires that a CAIR 
permit application properly identify the source and include the 
standard requirements under proposed sections Sec. Sec.  96.121 and 
96.221. The CAIR cap-and-trade program permit application should 
include all elements of the program (including the standard 
requirements). Such an approach allows the permitting authority to 
incorporate virtually all of the applicable CAIR cap-and-trade program 
requirements into a CAIR permit by including as part of such permit the 
CAIR permit application submitted by the source. Directly incorporating 
the CAIR permit application into the CAIR permit and, thus, into the 
source's operating permit or the overarching permit minimizes the 
administrative burden on the permitting authority of including the CAIR 
cap-and-trade program applicable requirements. The permitting authority 
may revise the term of the CAIR permit as necessary to facilitate 
coordination of the renewal with the issuance, revision, or renewal of 
the sources title V permit.
    d. Sections 96.124 and 96.224, CAIR permit revisions. For revisions 
to the CAIR permit, the CAIR trading program again defers to the 
regulations addressing permits revisions promulgated by the permitting 
authority under title V and 40 CFR part 70 or 71. The proposal also 
provides that the allocation, transfer, or deduction of allowances is 
automatically incorporated in the CAIR permit, and does not require a 
permit revision or reopening by the permitting authority. The CAIR 
permit must, however, expressly state that each source must hold enough 
allowances to account for emissions by the allowance transfer deadline 
for each control period. The EPA believes that requiring the permitting 
authority to revise or reopen a CAIR permit each time a CAIR allowance 
allocation, transfer, or deduction is made would be burdensome and 
unnecessary.

[[Page 32717]]

4. Subpart DD and DDD, CAIR Compliance Certification
    Sections 96.130 through 96.131 and 96.230 through 96.231 are 
reserved. The NO_X and SO₂ cap-and-trade programs 
in today's SNPR do not include the requirement for the source to submit 
a compliance certification report. The requirements are unnecessary 
because these sources already certify compliance with the emissions 
monitoring and reporting requirements when they submit their quarterly 
emissions data. In addition, these sources will submit compliance 
certifications under title V for all CAA requirements, including the 
CAIR, NO_X SIP Call, and Acid Rain trading programs.
5. Subpart EE and EEE, CAIR NO_X and SO₂ Allowance 
Allocations
    Sections 96.140 through 96.142 of today's SNPR propose both 
required provisions (i.e., State-by-State NO_X emissions 
budgets and the timing for States to report unit-by-unit NO_X 
allocations) as well as the example allocation approach, provided as an 
illustration. Specifically, sections 96.140 and 96.240 propose the 
State-by-State NO_X emission budgets that may be allocated by 
the State. Section 96.141 proposes elements of the NO_X 
allocation systems that States are required to include (i.e., a 3 year 
minimum for advanced notification by the State of allocations and the 
annual timing of submitting to EPA the updated, unit-by-unit 
allocations) in order to ensure consistency for sources across all 
States participating in the EPA-managed cap-and-trade program. Section 
96.142 proposes provisions that would implement the example approach 
for the NO_X cap-and-trade program--discussed in detail in 
above, including procedures for creating a new unit set-aside and 
incorporating new units into a permanent allocation.
    Sections 96.240 through 242, pertaining to the CAIR SO₂ 
cap-and-trade program, are reserved. The title IV SO₂ 
allowance allocation provisions of the CAA remain in effect. Should the 
final CAIR program make CAIR SO₂ allowances available to the 
States, EPA would include requirements for a 3 year minimum for 
advanced notification for unit-by-unit allocations that would be 
similar to those proposed for NO_X allocations in today's 
action.
6. Subpart FF and FFF, CAIR NO_X and SO₂ Allowance 
Tracking Systems.
    a. Overview of tracking system. Sections 96.150 through 96.157 and 
96.250 through 96.257 of today's proposed model rule cover the system 
to track CAIR NO_X and SO₂ allowances. The 
proposed rule is intended to make use of the allowance tracking systems 
developed for the NO_X SIP Call and Acid Rain Program, with 
some modifications. Such an approach would help to allow the 
integration of the CAIR NO_X and SO₂ cap-and-trade 
programs with the existing cap-and-trade programs under the 
NO_X SIP Call and Acid Rain Program. It would also save 
industry and government the time and resources necessary to develop new 
tracking systems.
    The current automated systems will be used to track CAIR 
NO_X and SO₂ allowances held by CAIR sources under 
the CAIR NO_X and SO₂ cap-and-trade programs, as 
well as those allowances held by other organizations or individuals. 
Specifically, the systems would track the allocation of all CAIR 
NO_X and SO₂ allowances, holdings of CAIR 
NO_X and SO₂ allowances in accounts, deduction of 
CAIR NO_X and SO₂ allowances for compliance 
purposes, and transfers between accounts. The primary role of the 
tracking system is to provide an efficient, transparent, and automated 
means of monitoring compliance with the CAIR NO_X and 
SO₂ cap-and-trade programs. It would also provide the 
allowance market with a record of ownership of allowances, dates of 
allowance transfers, buyer and seller information, and the serial 
numbers of allowances transferred.
    The EPA is proposing that the tracking system contain two primary 
types of accounts: Compliance accounts and general accounts. The EPA is 
proposing that compliance accounts for NO_X and 
SO₂ be created for each CAIR source with one or more CAIR 
units, upon receipt of the Certificate of Representation form. General 
accounts are created for any organization or individual upon receipt of 
a General Account Information form.
    b. Establishment of accounts.
    i. Compliance accounts. The EPA is proposing to require source-
level accounts for compliance with the CAIR NO_X and 
SO₂ cap-and-trade programs. The EPA's experience in 
conducting compliance determinations (reconciliation) for the Acid Rain 
cap-and-trade program at strictly the unit level indicates that there 
is the potential for affected facilities to be subject to monetary 
penalties simply for having too few allowances in one unit account at a 
source when there are plenty of available allowances at another unit 
account at the same source. This amounts to a monetary penalty, 
potentially large, for an accounting error that has no significant 
environmental effect. In developing the compliance procedures for the 
NO_X SIP Call cap-and-trade programs, this was taken into 
consideration and overdraft accounts were introduced to provide some 
flexibility in managing allowances at a source. However, both EPA and 
the regulated community find that, in practice, overdraft accounts and 
their use can be quite complicated and do not significantly reduce the 
burden of unit-level accounting. Therefore, EPA is proposing compliance 
accounts be established at the source level. This will significantly 
reduce the accounting burden for both EPA and the regulated community 
without causing any environmental consequences. The source-level 
accounts would be identified by a account number incorporating the 
source's Office of Regulatory Information System's (ORIS) code or 
facility identification number.
    Today's SNPR also modifies the Acid Rain Program regulations to 
provide for source-level compliance. This will facilitate the 
interaction of the Acid Rain Program and the CAIR cap-and-trade programs.
    ii. General accounts. Today's proposed model rules allow any person 
or group to open a general account. These accounts would be identified 
by the ``9999'' that would compose the first four digits of the account 
number. Unlike compliance accounts, general accounts cannot be used for 
compliance but can be used for holding or trading NO_X or 
SO₂ allowances (e.g., by allowance brokers or owners of 
multiple CAIR NO_X or SO₂ units or sources). 
General accounts are currently used for both SO₂ allowances 
in the Acid Rain Program and NO_X allowances in the 
NO_X SIP Call cap-and-trade program.
    To open a general account, a person or group must complete the 
standard General Account Information form, which is similar to the 
Certificate of Representation that precedes the opening of a compliance 
account. The form must include the name of a natural person who would 
serve as the NO_X or SO₂ Authorized Account 
Representative (AAR). The form would include identifying information 
for the AAR and alternate AAR (if applicable); the organization name 
and type, if applicable; the names of all parties with an ownership 
interest with the respect to the NO_X or SO₂ 
allowances in the account; and certification language and signatures of 
the NO_X or SO₂ AAR and alternate, if applicable.
    Revisions to information regarding an existing general account are 
made by submitting a new General Account Information form which would 
be sent to EPA in all cases, whether the form is

[[Page 32718]]

used to open a new account, or revise information on an existing one. 
The EPA would notify the NO_X or SO₂ AAR cited on 
the application of the establishment of his or her general account or 
of the registration of requested changes.
    c. Recordation of allowance allocations. The NO_X 
allocations for existing units for the first 5 years (2010-2014), as 
prescribed by each State, would be recorded into the CAIR 
NO_X (source-level) compliance accounts prior to the first 
control period in 2010. Prior to the second control period, in 2011, 
and each year thereafter, NO_X allocations for the new fifth 
sixth year, as prescribed by each State, would be recorded in each 
compliance account (e.g., in 2011, year 2016 NO_X allowances 
would be allocated).
    Title IV SO₂ allowances are allocated and recorded under 
the Acid Rain Program so this section of the CAIR SO₂ model 
cap-and-trade rules is reserved. Should the final CAIR rule make CAIR 
SO₂ allowances available to States, requirements for the 
recordation of CAIR SO₂ allowances would be similar to those 
proposed for NO_X allocations in today's action.
    d. Compliance. Once a control period has ended (i.e., December 31) 
CAIR NO_X and SO₂ sources would have a window of 
opportunity (i.e., until the allowance transfer deadline of midnight on 
March 1 following the control period) to evaluate their reported 
emissions and obtain any additional NO_X or SO₂ 
allowances they may need to cover the emissions during the year.
    NO_X: The compliance requirement would be to hold one NOx 
allowance for each ton of NO_X emissions at each CAIR unit at 
the source. For each ton of NO_X emissions for which the 
source does not hold an allowance, the excess emissions offset would be 
a deduction of 3 NO_X allowances allocated for the year after 
the year in which the excess emissions occur.
    SO₂: The compliance requirement would depend upon the 
vintage of the SO₂ allowance being submitted for compliance. 
For allowances with vintage years of 2009 and earlier, one 
SO₂ allowance must be held for each ton of SO₂ 
emissions. For allowances for vintage years 2010-2014, a source must 
hold 2 allowances of these vintages for each ton of SO₂ 
emissions. A source must hold 3 SO₂ allowances of vintage 
years 2015 and beyond for each ton of SO₂ emissions at the 
source. For each ton of SO₂ emissions for which the source 
does not hold the requisite number of SO₂ allowances, the 
excess emissions offset would deduct three times the number of 
SO₂ allowances required for the sources emissions for the 
vintage year immediately following the year in which the excess 
emissions occurred. This would result in six 2010-2014 vintage year 
allowances and nine 2015 and beyond year allowances, since two 2010-
2014 allowances or three 2015 and beyond allowances authorize one ton 
of SO₂ emissions.
    The EPA believes that it is important to include this automatic 
offset deduction because it ensures that non-compliance with the 
NO_X and SO₂ emission limitations of this part is 
a more expensive option than controlling emissions. The EPA required an 
automatic deduction of 3-for-1 in the NO_X SIP Call, and is 
taking comment on the ratios used in the proposed model rules. The 
automatic offset provisions do not limit the ability of the permitting 
authority or EPA to take enforcement action under State law or the CAA.
    In the Acid Rain Program, one SO₂ allowance must be held 
for each ton of SO₂ emissions. As discussed above, one, two, 
or three SO₂ allowances must be held for each ton of 
emissions, depending on the year for which the allowances were 
allocated. Consequently, non-compliance with the allowance-holding 
requirement in the CAIR SO₂ cap-and-trade program would not 
necessarily mean non-compliance with the allowance-holding requirement 
in the Acid Rain Program. Therefore, it is necessary to ensure that 
compliance with the Acid Rain Program allowance-holding requirements is 
assessed independently from the CAIR requirements. The EPA is proposing 
a detailed allowance deduction order for each CAIR unit at each CAIR 
source where one allowance for each ton of emissions is deducted first 
(satisfying the Acid Rain requirement) and then the additional 
allowances are deducted to complete the CAIR SO₂ requirement.
    e. Banking. Banking is the retention of unused allowances from one 
control period for use in a later control period. Banking allows 
sources to create reductions beyond required levels and ``bank'' the 
unused allowances for use later. The EPA is proposing that banking of 
allowances after the start of the CAIR NO_X and 
SO₂ cap-and-trade programs be allowed with no restriction. 
Banking after a program starts and the budget is imposed allows sources 
to retain any allowances not surrendered for compliance at the end of 
each control period. Once the CAIR cap-and-trade program budgets are in 
place, sources may over-control for one or more years and withdraw from 
the bank in one or more later years. This type of banking provides the 
following advantages: Encourages early reductions, stimulates the 
market, and provides flexibility to sources, while also potentially 
causing NO_X or SO₂ emissions in some control 
periods to be greater than the allowances allocated for those years.
    Allowing unrestricted banking is consistent with the current Acid 
Rain Program for SO₂. The NO_X SIP Call cap-and-
trade program, however, has some restrictions on the use of banked 
allowances, a procedure called flow control. Flow control was first 
used in the OTC NO_X cap-and-trade program and was carried 
over into the NO_X SIP Call cap-and-trade program. The flow 
control provisions were designed to discourage extensive use of banked 
allowances in a particular ozone season. Flow control establishes a 2-
to-1 discount ratio on the use of banked allowances above a certain 
level. The discount ratio applies after the total number of banked 
allowances from all sources exceeds 10 percent of the regionwide 
NO_X emissions budget. Flow control is a very complicated 
procedure to explain, understand, and implement. The experience in the 
OTC cap-and-trade program illustrated that flow control can cause 
allowance market complexity and confusion for the regulated community 
by stratifying the allowance market by vintages (i.e., the year for 
which the allowances are allocated), making banked allowances less 
valuable, and potentially increasing the cost of compliance. In 
addition to these negative effects, it remains difficult to ascertain 
an environmental benefit. The EPA is proposing to not use flow control 
in order to keep compliance with the CAIR cap-and-trade programs as 
simple and easy as possible.
7. Subparts GG and GGG, CAIR NO_X and SO₂ 
Allowance Transfers
    The EPA is proposing that once a NO_X or SO₂ 
DR or AAR is appointed and an account is established, NO_X or 
SO₂ allowances can be transferred to or from the accounts 
with the submission of allowance transfer information, either on-line 
or through the use of an Allowance Transfer form. Transfers can occur 
between any accounts at any time of year with one exception: Transfers 
of current and past year allowances into and out of compliance accounts 
are prohibited after the allowance transfer deadline (March 1 following 
each control period) until EPA completes the annual reconciliation 
process by deducting the necessary allowances.
    For those electing not to transfer allowances on-line, there would 
be one standard NO_X and one standard SO₂ 
Allowance Transfer form. This form would be submitted to the EPA in all

[[Page 32719]]

cases. The form would generally include: the transferor and transferee 
allowance account numbers; the transferor's printed name, phone number, 
signature, and date of signature; and a list of allowances to be 
transferred, by serial number.
8. Subparts HH and HHH, CAIR NO_X and SO₂ 
Monitoring and Reporting
    Clear, rigorous, and transparent monitoring and reporting of all 
emissions are the basis for holding sources accountable for their 
emissions and are essential to the success of any cap-and-trade 
program. Consistent and accurate measurement of emissions ensures that 
each allowance actually represents one ton of emissions and that one 
ton of reported emissions from one source is equivalent to one ton of 
reported emissions from another source. Similarly, such measurement of 
emissions ensures that each single allowance (or group of 
SO₂ allowances, depending upon the SO₂ allowance 
vintage) represents one ton of emissions, regardless of the source for 
which it is measured and reported. This establishes the integrity of 
each allowance, which instills confidence in the underlying market 
mechanisms that are central to providing sources with flexibility in 
achieving compliance. Given the variability in the type, operation, and 
fuel mix of sources in the proposed CAIR NO_X and 
SO₂ cap-and-trade programs, EPA believes that emissions must 
be monitored continuously in order to ensure the precision, 
reliability, accuracy, and timeliness of emissions data that support a 
cap-and-trade program. As proposed, part 96 subpart HH for 
NO_X and subpart HHH for SO₂ establish monitoring 
and reporting requirements for CAIR sources. These subparts reference 
the relevant sections of part 75 where the specific procedures and 
requirements for measuring and reporting NO_X and 
SO₂ mass emissions are found. These subparts are modeled 
after subpart H of part 96.
    Part 75 was originally developed for the Acid Rain Program. The 
Acid Rain Program, as established by Congress in the 1990 Amendments to 
the Act, requires the use of continuous emissions monitoring systems 
(CEMS) or an alternative monitoring system that is demonstrated to 
provide information with the same precision, reliability, accuracy, and 
timeliness as a CEMS. The EPA believes that the use of CEMS is a 
critical part of ensuring the effectiveness of regional cap-and-trade 
programs. In implementing the Acid Rain Program, as well as the 
NO_X SIP Call Trading Program, EPA has allowed alternatives 
to CEMS only where the total of the emissions contributed by specified 
categories of affected sources is de minimis in comparison to the 
emissions cap for the program, or where an alternative monitoring 
system has been demonstrated, according to specified criteria, to meet 
the standard Congress set. Provisions for monitoring and reporting 
NO_X mass emissions were added to Acid Rain Program 
methodologies for both the OTC NO_X Budget Program and for 
the NO_X SIP Call. As a result, several alternative 
monitoring methodologies exist for qualifying sources to use. For 
example, there is a SO₂ emissions data protocol that allows 
gas- or oil-fired units to use fuel sampling techniques along with fuel 
flow metering to quantify emissions. (See part 75, appendix D.) There 
is also a NO_X estimation methodology for certain 
infrequently used gas- or oil-fired units that can be found in part 75, 
appendix E. There are also optional emissions calculation procedures 
for gas-or oil-fired sources emitting no more than 25 tons of 
SO₂ annually or less than 100 tons of NO_X 
annually which allow the use of conservative emission factors to 
estimate emissions. (See Sec.  75.19.) All of the existing part 75 
monitoring methodologies will be available to CAIR sources as applicable.
    Sources subject to the CAIR must monitor and report NO_X 
and SO₂ mass emissions year round. The majority of CAIR 
sources are measuring and reporting SO₂ mass emissions year 
round under the Acid Rain Program. Therefore, these sources will have 
little or no changes to make to their monitoring and reporting efforts 
under the CAIR. Most CAIR sources are also reporting NO_X 
mass emissions year round under the NO_X SIP Call. The CAIR-
affected Acid Rain sources that are located in States that are not 
affected by the NO_X SIP Call currently measure and report 
NO_X emission rates year round, but do not currently report 
NO_X mass emissions. These sources will need to modify only 
their reporting practices in order to comply with the proposed CAIR 
monitoring and reporting requirements. Today's SNPR is designed to be 
as consistent as possible with existing requirements in order to 
minimize the impact on CAIR sources of the monitoring and reporting 
requirements, while maintaining the integrity of the cap-and-trade 
programs.
    The requirement to monitor and the associated monitoring deadlines 
are found in Sec.  96.170 for NO_X and Sec.  96.270 for 
SO₂ for the CAIR trading programs and require continuous 
measurement of SO₂ and NO_X emissions by all 
existing affected sources by January 1, 2009 using part 75 certified 
monitoring methodologies. New sources have separate deadlines based 
upon the date of commencement of operation, consistent with the Acid 
Rain Program.
    The quality assurance (QA) requirements for the Acid Rain Program 
that were mandated by Congress under the CAA have been codified in 
appendices A and B of part 75. Part 75 specifies that each CEMS must 
undergo rigorous initial certification testing and periodic quality 
assurance testing thereafter, including the use of relative accuracy 
test audits (RATAs) and daily calibrations. A standard set of data 
validation rules apply to all of the monitoring methodologies. These 
stringent requirements result in an accurate accounting of the mass 
emissions from each affected source and provide prompt feedback if the 
monitoring system is not operating properly. In addition, when the CEMS 
is not operating properly, standard substitute data procedures are 
applied and result in a conservative estimate of emissions for the 
period involved. This ensures a level playing field among the regulated 
sources with consistent accounting for every ton of emissions and also 
provides an incentive to keep the monitoring system properly up to date 
with QA requirements. The NO_X SIP Call trading program also 
requires part 75 QA procedures. The EPA proposes to require the same QA 
procedures (as applied to an entire year, not just the ozone season) 
for the CAIR program. Initial certification or recertification is 
required as specified in Sec. Sec.  96.171 and 96.271. Recognizing that 
many of the CAIR units are already monitoring NO_X or 
SO₂ (sometimes both) under part 75 through existing 
programs, subparts HH and HHH allow continued use of previously 
certified CEMS when appropriate rather than automatically requiring 
recertification. Requirements for reporting data when the monitors do 
not meet QA specifications are found in Sec. Sec.  96.172 and 96.272.
    Sections 96.174 and 96.274 specify reporting requirements, which 
include general requirements, monitoring plan reporting, certification 
applications, quarterly emissions and operations reports, and 
compliance certifications. The EPA proposes to require year-round 
reporting of emissions and monitoring data from each affected unit. As 
required for the Acid Rain Program and the NO_X SIP Call 
trading programs, quarterly emissions reports must be submitted to EPA 
electronically on a quarterly basis and in a format specified by the 
Agency using EPA-provided software. Many affected sources are

[[Page 32720]]

already reporting some or all of this data to EPA under either the Acid 
Rain Program or the NO_X SIP Call trading program and can 
continue to report that data along with any additional data that may be 
required by this program. The EPA has found centralized reporting to be 
necessary to ensure consistent review, checking, and posting of the 
emissions and monitoring data for all affected sources, which 
contributes to the integrity, efficiency, and transparency of the 
trading program. Another important feature is that sources regulated 
under the Acid Rain Program, NO_X SIP Call, or the CAIR 
NO_X and SO₂ cap-and-trade programs must use the 
same reporting format and submit only one report with all of the 
information required for all of the applicable programs. Thus, if the 
same data is needed for multiple programs, the source needs to report 
it only once in the form of one comprehensive report.
    Consistent with the current monitoring and reporting requirements 
in part 75 for the Acid Rain and the NO_X SIP Call programs, 
the proposed rule would allow sources, Sec.  96.175 of subpart HH of 
part 96 and under Sec.  96.275 of subpart HHH of part 96, to petition 
for an alternative to any of the specified monitoring requirements in 
the rule. These provisions provide sources with the flexibility to 
petition to use an alternative monitoring system under subpart E of 
part 75 or variations of the standard monitoring requirements as long 
as the requirements of existing Sec.  75.66 are met.
    Sections 96.176 and 96.276 require heat input data to be measured 
and reported regardless of the type of monitoring system.

V. Clarifications to January 30, 2004 Proposal

    This section provides clarifications to the January 2004 proposal 
where the preamble language provided in the published proposal was 
unclear, incomplete, inadvertently omitted, or inadvertently incorrect. 
Unless otherwise indicated, all references to the Federal Register--69 
FR 4566-4650--are to the proposed Interstate Air Quality Rule.

A. Scope of the Proposed Action

    On 69 FR 4633 column 1, EPA discussed the NO_X cap-and-
trade program. Under the heading ``States Outside the Proposed Region 
with Existing Regional NO_X Cap-and-trade Programs'', EPA 
mistakenly identified Massachusetts in the list of States that 
participate in existing NO_X trading markets that would not 
be affected by the proposed rules. Massachusetts should be deleted from 
that list because it would be affected by the proposed rules.
    In the January 2004 proposal, we discussed regional control 
requirements and budgets based on a showing of ``significant 
contribution'' by upwind States to nonattainment in other States. (69 
FR 4611-4613). CAA section 110(a)(2)(D), which provides the authority 
for the proposal, states among other things that SIPs must contain 
adequate provisions prohibiting, consistent with the CAA, sources or 
other types of emissions activity within a State from emitting 
pollutants in amounts that will ``contribute significantly to 
nonattainment in, or interfere with maintenance by, any other State 
with respect to'' the NAAQS.
    Thus, CAA section 110(a)(2)(D) requires that States prohibit 
emissions that contribute significantly to downwind nonattainment. In 
the January 2004 proposal, we discussed both the air quality component 
and the cost-effectiveness component of the ``contribute 
significantly'' determination. The EPA has interpreted CAA section 
110(a)(2)(D) to require that States reduce emissions by specified 
amounts, and has based those amounts on the availability of highly 
cost-effective controls for certain source categories. Following this 
interpretation, EPA based the January 2004 proposal on the availability 
of highly cost-effective reductions of SO₂ and 
NO_X from EGUs in States that meet EPA's proposed inclusion 
criteria.
    We noted in the January 2004 proposal, with respect to the cost-
effectiveness component, that one factor we consider in determining 
cost effectiveness is the identification of source categories which 
emit relatively large amounts of the relevant emissions. We noted that 
this element is particularly important in a case such as the proposed 
CAIR where the Federal government is proposing a multi-State regional 
approach to reducing transported pollution. (69 FR 4611).
    One approach cited in the January 2004 proposal for ensuring that 
both the air quality component and the cost effectiveness component of 
the section 110 ``contribute significantly'' determination is met, is 
to consider a source category's contribution to ambient concentrations 
above the attainment level in all nonattainment areas in affected 
downwind States. Some have recommended a further refinement of this 
concept, suggesting that a source category should be included only if 
the proposed level of additional control of that category would meet a 
specified threshold. Under this suggested approach, EPA could 
determine, for example, that inclusion of a source category in a broad 
multi-State SIP call would be appropriate only if it would result in at 
least 0.5 percent of U.S. counties and/or parishes in the lower 48 
States coming into attainment with a NAAQS. Given the number of 
counties and parishes in the United States, this requirement would be 
met if at least 16 counties in the lower 48 States were brought into 
attainment with a NAAQS as a result of the proposed level of control on 
a particular source category. Choice of a factor as low as 0.5 percent 
of U.S. counties and/or parishes reflects the fact, according to this 
approach, that, for every NAAQS, the vast majority of counties are 
already in attainment. Nevertheless, for most criteria pollutants, this 
figure represents a significant portion of the remaining nonattainment 
problem.
    The EPA seeks comment on whether this test should be incorporated 
as a part of the ``highly cost-effective'' component of the 
``contribute significantly'' requirement of CAA section 110(a)(2)(D) 
when a multi-State call for SIP revisions to address interstate 
transport of air pollution is at issue. The EPA has conducted air 
quality modeling of the January 2004 proposal which indicates that the 
proposed emissions reductions will bring 34 additional areas (from a 
base of 73 down to 39) into attainment with either the PM2.5 or 8-hour 
ozone NAAQS by 2015. Since there are over 3,000 counties and parishes 
in the lower 48 States, basing the highly cost-effective control levels 
in the proposed CAIR on EGUs would meet this 0.5 percent criterion.
    States retain authority to decide which sources to control to 
achieve the required amounts of reductions, but EPA considers the costs 
of controls for more sources in determining what is a significant 
contribution. Other CAA mechanisms, such as SIP disapproval authority 
and State petitions under CAA section 126, are available to address 
more isolated instances of the interstate transport of pollutants.

B. Summary of Control Costs

    The control cost summary provided on 69 FR 4632 column 2 indicates 
a marginal cost per ton of SO₂ emissions of $805 in the 
first phase, and $989 in the second phase, of the proposed control 
program. These amounts were based on modeling performed to evaluate the 
implications of using retirement ratios to implement the emission 
reduction requirements of the

[[Page 32721]]

rule. This modeling is different from the modeling used to evaluate 
highly cost-effective controls. The latter modeling is summarized in 
Table VI-1 on 69 FR 4613, and shows marginal costs of $700 per ton in 
the first phase, and $1000 per ton in the second phase.

C. Source of Cost Information

    On 69 FR 4614, Table VI-4, EPA failed to include an additional 
footnote referencing the source of the cost information for the last 
entry in the table, ``Revision of NSPS for New EGUs.'' The footnote 
should have indicated that the cost information is derived from 
``Proposed Revision of Standards of Performance for Nitrogen Oxide 
Emissions from New Fossil-Fuel Fired Steam Generating Units: Proposed 
Revisions to Reporting Requirements for Standards of Performance for 
New Fossil-Fuel Fired Steam Generating Units,'' 62 FR 36951. The 
control costs for SCR shown in the table are for coal-fired utility 
steam generating units and coal-fired industrial steam generating 
units. The proposed NSPS revision included ranges of costs; EPA 
presented the mid-point from those ranges in the table.

D. Judicial Review Under Clean Air Act Section 307

    The EPA did not discuss in the January 2004 proposal the applicable 
provisions for judicial review of CAA section 307. Section 307(b)(1) 
indicates in which Federal Courts of Appeal petitions of review of 
final actions by EPA must be filed. This section provides, in part, 
that petitions for review must be filed in the Court of Appeals for the 
District of Columbia Circuit if (i) the agency action consists of 
``nationally applicable regulations promulgated, or final action taken, 
by the Administrator,'' or (ii) the agency action is locally or 
regionally applicable, but ``such action is based on a determination of 
nationwide scope or effect and * * * in taking such action the 
Administrator finds and publishes that such action is based on such a 
determination.''
    Any final action related to the CAIR is ``nationally applicable'' 
within the meaning of section 307(b)(1). As an initial matter, through 
this rule, EPA interprets section 110(a)(2)(D)(i) of the CAA in a way 
that could affect future actions regulating the transport of 
pollutants. In addition the January 2004 proposal would require 29 
States and the District of Columbia to decrease emissions of either 
SO₂ or NO_X, or both. The Interstate Air Quality 
Rule is based on a common core of factual findings and analyses 
concerning the transport of ozone, PM2.5 and their precursors between 
the different States subject to the Interstate Air Quality Rule. 
Finally, EPA has established uniform approvability criteria that would 
be applied to all States subject to the Interstate Air Quality Rule. 
For these reasons, the Administrator also is determining that any final 
action regarding the Interstate Air Quality Rule is of nationwide scope 
and effect for purposes of section 307(b)(1). Thus, any petitions for 
review of final actions regarding the Interstate Air Quality Rule must 
be filed in the Court of Appeals for the District of Columbia Circuit 
within 60 days from the date final action is published in the Federal 
Register.

VI. Statutory and Executive Order Reviews

    This section of the SNPR discusses reviews conducted to meet the 
requirements of applicable statutes and executive orders. In the 
January 2004 proposal (69 FR 4566, January 30, 2004), EPA addressed the 
regulatory requirements that trigger statutory and executive order 
reviews. This supplemental proposal does not add substantive regulatory 
requirements. Rather, in general, it proposes a legal determination 
that implementation of the model rule will meet the better-than-BART 
requirements, clarifies aspects of the January 2004 proposal, and adds 
regulatory text for the proposals in the January 2004 proposal. 
Therefore, this supplemental proposal does not alter the findings of 
the January 2004 proposal.
    The EPA provides additional information below relating to the 
National Technology Transfer and Advancement Act. In addition, the EPA 
plans to conduct additional analyses as discussed in the January 2004 
proposal relating to the Paperwork Reduction Act (PRA), the Regulatory 
Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as amended by the Small 
Business Regulatory Enforcement Fairness Act (Pub. L. 104-121) 
(SBREFA), and the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) 
(UMRA) in the Notice of Final Rulemaking for this action. The EPA 
believes the analyses relating to the RFA and UMRA are not required for 
this rule by statute, but these analyses will be conducted for 
informational purposes. While it doesn't alter EPA's findings, EPA has 
performed additional analysis of the impact that the proposed CAIR may 
have on States not affected by the proposed CAIR. This analysis is 
available in the docket.
    National Technology Transfer Advancement Act. Section 12(d) of the 
National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. 
L. 104-113; 15 U.S.C. 272 note) directs EPA to use voluntary consensus 
standards in their regulatory and procurement activities unless to do 
so would be inconsistent with applicable law or otherwise impractical. 
Voluntary consensus standards are technical standards (e.g., materials 
specifications, test methods, sampling procedures, business practices) 
developed or adopted by one or more voluntary consensus bodies. The 
NTTAA directs EPA to provide Congress, through annual reports to OMB, 
with explanations when an agency does not use available and applicable 
voluntary consensus standards.
    This SNPR would require all sources that participate in the trading 
program under proposed part 96 to meet the applicable monitoring 
requirements of part 75. Part 75 already incorporates a number of 
voluntary consensus standards. Consistent with the Agency's Performance 
Based Measurement System (PBMS), part 75 sets forth performance 
criteria that allow the use of alternative methods to the ones set 
forth in part 75. The PBMS approach is intended to be more flexible and 
cost effective for the regulated community; it is also intended to 
encourage innovation in analytical technology and improved data 
quality. At this time, EPA is not proposing any revisions to part 75, 
however EPA periodically revises the test procedures set forth in part 
75. When EPA revises the test procedures set forth in part 75 in the 
future, EPA will address the use of any new voluntary consensus 
standards that are equivalent. Currently, even if a test procedure is 
not set forth in part 75, EPA is not precluding the use of any method, 
whether it constitutes a voluntary consensus standard or not, as long 
as it meets the performance criteria specified. However, any 
alternative methods must be approved through the petition process under 
Sec.  75.66 before they are used under part 75. We welcome comments on 
this aspect of the proposed rulemaking and, specifically, invite the 
public to identify potentially applicable voluntary consensus standards 
and to explain why EPA should use such standards in this regulation.

VII. Proposed Rule Text

    This SNPR includes the proposed rule text for the CFR for the basic 
elements of the CAIR proposal. This rule text includes the requirements 
for the affected jurisdictions to submit transport SIPs under the 
PM_2.5 standard, the 8-hour ozone standard, or both; as well 
as for implementation of the

[[Page 32722]]

applicable SO₂ and NO_X emissions budgets. It also 
includes model rule language that States may adopt for interstate 
trading rules. The rule language is located at the end of the preamble.
    Specifically, EPA is today proposing to amend or revise the 
following rule text:

(i) Part 51 subpart A, Sec. Sec.  51.1 through 51.45;
(ii) Part 51 subpart G, Sec. Sec.  51.122 through 51.125;
(iii) Part 51, Sec.  51.308;
(iv) Part 72, Sec.  72.2;
(v) Part 73, various Sec. Sec.  73.1 through 73.70;
(vi) Part 74, various Sec. Sec.  74.18 through 74.50;
(vii) Part 77, various Sec. Sec.  77.3 through 77.6;
(viii) Part 78, Sec. Sec.  78.1, 78.3, 78.4 and 78.12;
(ix) Part 96, Sec. Sec.  96.101 through 96.186 (NO_X trading) 
and Sec. Sec.  96.201 through 96.286 (SO₂ trading).

List of Subjects

40 CFR Part 51

    Environmental Protection, Administrative practice and procedure, 
Air pollution control, Intergovernmental relations, Nitrogen dioxide, 
Ozone, Particulate matter, Reporting and recordkeeping requirements, 
Sulfur oxides.

40 CFR Parts 72, 73, 74, 77 and 78

    Environmental Protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Electric utilities, Intergovernmental 
relations, Nitrogen oxides, Reporting and recordkeeping requirements, 
Sulfur oxides.

40 CFR Part 96

    Environmental Protection, Administrative practice and procedure, 
Air pollution control, Nitrogen oxides, Reporting and recordkeeping 
requirements.

    Dated: May 18, 2004.
Michael O. Leavitt,
Administrator.

    Title 40, chapter I, of the Code of Federal Regulations is proposed 
to be amended as follows:

PART 51--[AMENDED]

    1. The authority citation for part 51 continues to read as follows:

    Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.

    2. Part 51 subpart A is revised to read as follows:
Subpart A--Emission Inventory Reporting Requirements

General Information for Inventory Preparers

Sec.
51.1 Who is responsible for actions described in this subpart?
51.5 What tools are available to help prepare and report emissions 
data?
51.10 How does my State report emissions that are required by the 
NOX SIP Call and the Clean Air Interstate Rule?

Specific Reporting Requirements

51.15 What data does my State need to report to EPA?
51.20 What are the emission thresholds that separate point and non-
point sources?
51.25 What geographic area must my State's inventory cover?
51.30 When does my State report which emissions data to EPA?
51.35 How can my State equalize the emissions inventory effort from 
year-to-year?
51.40 In what form and format should my State report the data to 
EPA?
51.45 Where should my State report the data?

Appendix A to Subpart A of Part 51--Tables and Definitions
Appendix B to Subpart A of Part 51--[Reserved]

Subpart A--Emission Inventory Reporting Requirements

General Information for Inventory Preparers

Sec.  51.1  Who is responsible for actions described in this subpart?

    States must inventory emission sources located on non-tribal lands 
and report this information to EPA.

Sec.  51.5  What tools are available to help prepare and report 
emissions data?

    We urge your State to use estimation procedures described in 
documents from the Emission Inventory Improvement Program (EIIP). These 
procedures are standardized and ranked according to relative 
uncertainty for each emission estimating technique. Using this guidance 
will enable others to use your State's data and evaluate its quality 
and consistency with other data.

Sec.  51.10  How does my State report emissions that are required by 
the NO_X SIP Call and the Clean Air Interstate Rule ?

    The District of Columbia and States that are subject to the 
NO_X SIP Call (Sec.  51.121) are subject to the emission 
reporting provisions of Sec.  51.122. The District of Columbia and 
States that are subject to the Clean Air Interstate Rule are subject to 
the emission reporting provisions of Sec.  51.125. This subpart A 
incorporates the pollutants, source, time periods, and required data 
elements for both of these reporting requirements.

Specific Reporting Requirements

Sec.  51.15  What data does my State need to report to EPA?

    (a) Pollutants. Report actual emissions of the following (see 
Definitions in appendix A to this subpart for precise definitions as 
required):
    (1) Required pollutants for triennial reports of annual (12-month) 
emissions for all sources and every-year reports of annual emissions 
from Type A sources:
    (i) Sulfur dioxide (SO₂).
    (ii) Volatile organic compounds (VOC).
    (iii) Nitrogen oxides (NO_X).
    (iv) Carbon monoxide (CO).
    (v) Lead and lead compounds.
    (vi) Primary PM_2.5. Emissions of filterable, 
condensible, and total PM_2.5. should be reported, if all are 
applicable to the source type.
    (vii) Primary PM₁₀. Emissions of filterable, 
condensible, and total PM₁₀ should be reported, if all are 
applicable to the source type.
    (viii) Ammonia (NH₃).
    (2) Required pollutants for every-year reporting of annual (12-
month) emissions for sources controlled to meet the requirements of 
Sec.  51.123: NO_X.
    (3) Required pollutants for every-year reporting of annual (12-
month) emissions of sources controlled to meet the requirements of 
51.124: SO₂.
    (4) Required pollutants for all reports of ozone season (5 months) 
emissions: NO_X.
    (5) Required pollutants for triennial reports of summer daily 
emissions:
    (i) NO_X.
    (ii) VOC.
    (6) Required pollutants for every-year reports of summer daily 
emissions: NO_X.
    (7) A State may at its option include in its emissions inventory 
reports estimates of emissions for additional pollutants such as other 
pollutants listed in paragraph (a)(1) or hazardous air pollutants.
    (b) Sources. Emissions should be reported from the following 
sources in all parts of the State, excluding sources located on tribal 
lands:
    (1) Point.
    (2) Non-point.
    (3) Onroad mobile.
    (4) Nonroad mobile.
    (c) Supporting information. You must report the data elements in 
Tables 2a through 2d of appendix A to this subpart. You must also 
report information on the method of determination for data elements EPA 
may designate for such reporting in each reporting period. Additional 
information not listed in Tables 2a through 2d may be required, for

[[Page 32723]]

example information identifying the State contact person for the 
submittal. We may ask you for other data on a voluntary basis to meet 
special purposes.
    (d) Confidential data. We do not consider the data in Tables 2a 
through 2d of appendix A to this subpart confidential, but some States 
limit release of this type of data. Any data that you submit to EPA 
under this rule will be considered in the public domain and cannot be 
treated as confidential. If Federal and State requirements are 
inconsistent, consult your EPA Regional Office for a final reconciliation.
    (e) Option to Submit Inputs to Emission Inventory Estimation Models 
in Lieu of Emission Estimates. For a given reporting year, EPA may 
allow States to submit comprehensive input values for models capable of 
estimating emissions from a certain source type on a national scale, in 
lieu of submitting the emission estimates otherwise required by this 
subpart.

Sec.  51.20  What are the emission thresholds that separate point and 
non-point sources?

    (a) All anthropogenic stationary sources must be included in your 
inventory as either point or non-point sources, except that biogenic 
emissions are not required to be reported.
    (b) Sources which are major sources under section 302 or part D of 
title I of the Clean Air Act, considering emissions only of the 
pollutants listed in Sec.  51.15(a), must be reported as point sources, 
starting with the 2008 inventory year. Provisions of part 70 affecting 
the definition of a major source apply to this subpart also. All 
pollutants specified in Sec.  51.15(a) must be reported for point 
sources, not just the pollutant(s) which qualify the source as a point 
source. Prior to the 2008 inventory year, States may omit from point 
source treatment any source that would not be major if its actual 
emissions were considered rather than its potential to emit.
    (c) If your State has lower emission reporting thresholds for point 
sources than paragraph (b) of this section, then you may use these in 
reporting your emissions to EPA.
    (d) All stationary sources that are not subject to reporting as 
point sources must be reported as non-point sources. This includes wild 
fires and prescribed fires. Episodic wind-generated particulate matter 
emissions from sources that are not major sources may be excluded, for 
example dust lifted by high winds from natural or tilled soil. 
Emissions of non-point sources may be aggregated to the county level, 
but must be separated and identified by source classification code 
(SCC). Non-point source categories or emission events reasonably 
estimated by the State to represent a de minimis percentage of total 
county and State emissions of a given pollutant may be omitted.

Sec.  51.25  What geographic area must my State's inventory cover?

    Because of the regional nature of these pollutants, your State's 
inventory must be statewide, regardless of any area's attainment status.

Sec.  51.30  When does my State report which emissions data to EPA?

    All States are required to report two basic types of emission 
inventories to EPA: Every-year Cycle Inventory; and Three-year Cycle 
Inventory. The sources and pollutant to be reported vary among States.
    (a) Every-year cycle. See Tables 2a, 2b, and 2c of appendix A to 
this subpart for the specific data elements to report every year.
    (1) All States are required to report every year the annual (12-
month) emissions of all pollutants listed in Sec.  51.15(a)(1) from 
Type A (large) point sources, as defined in Table 1. The first every-
year cycle inventory will be for the year 2003 and must be submitted to 
EPA within 17 months, i.e., by June 1, 2005. Subsequent every-year 
cycle inventories will be due 17 months following the end of the 
reporting year.
    (2) States subject to Sec. Sec.  51.123 and 51.125 of this subpart 
are required to report every year the annual (12-month) emissions of 
NO_X from any point, non-point, onroad mobile, or nonroad 
mobile source for which the State specified control measures in its SIP 
submission under Sec.  51.123 of this subpart. This requirement begins 
with the 2009 inventory year. This requirement does not apply to any 
State subject to Sec.  51.123 solely because of its contribution to 
ozone nonattainment in another State.
    (3) States subject to Sec. Sec.  51.124 and 51.125 of this subpart 
are required to report every year the annual (12-month) emissions of 
SO₂ from any point, non-point, onroad mobile, or nonroad 
mobile source for which the State specified control measures in its SIP 
submission under Sec.  51.124 of this subpart. This requirement begins 
with the 2009 inventory year.
    (4) States subject to Sec. Sec.  51.123 and 51.125 are required to 
report every year the ozone season emissions of NO_X and 
summer daily emissions of NO_X from any point, non-point, 
onroad mobile, or nonroad mobile source for which the State specified 
control measures in its SIP submission under Sec.  51.123 of this 
subpart. This requirement begins with the 2009 inventory year. This 
requirement does not apply to any State subject to Sec.  51.123 solely 
because of its contribution to PM_2.5 nonattainment in 
another State.
    (5) States subject to the emission reporting requirements of Sec.  
51.122 are required to report every year the ozone season emissions of 
NO_X and summer daily emissions of NO_X from any 
point, non-point, onroad mobile, or nonroad mobile source for which the 
State specified control measures in its SIP submission under Sec.  
51.121(g) of this subpart. This requirement begins with the inventory 
year prior to the year in which compliance with the NO_X SIP 
Call requirements is first required.
    (6) If sources report SO₂ and NO_X emissions 
data to EPA in a given year pursuant to a trading program approved 
under Sec.  51.123(o) or Sec.  51.124(o) of this part or pursuant to 
the monitoring and reporting requirements of subpart H of 40 CFR 75, 
then the State need not provide annual reporting of the pollutants to 
EPA for such sources. If SO₂ and NO_X are the only 
pollutants required to be reported for the source for the given 
calendar year and emissions period (annual, ozone season, or summer 
day), all data elements for the source may be omitted from the State's 
emissions report for that period. We will make both the raw data 
submitted by sources to the trading programs and summary data available 
to any State that chooses this option.
    (7) In years which are reporting years under the 3-year cycle, the 
reporting required by the 3-year cycle satisfies the requirements of 
this paragraph.
    (b) Three-year cycle. See Tables 2a, 2b and 2c of appendix A to 
this subpart for the specific data elements that must be reported 
triennially.
    (1) All States are required to report for every third year the 
annual (12-month) emissions of all pollutants listed in Sec.  
51.15(a)(1) from all point sources, non-point sources, onroad mobile 
sources, and nonroad mobile sources. The first 3-year cycle inventory 
will be for the year 2005 and must be submitted to us within 17 months, 
i.e., by June 1, 2007. Subsequent 3-year cycle inventories will be due 
17 months following the end of the reporting year.
    (2) States subject to Sec.  51.122 must report ozone season 
emissions and summer daily emissions of NO_X from all point 
sources, non-point sources, onroad mobile sources, and nonroad mobile 
sources. The first 3-year cycle inventory will be for the year 2005 and 
must be submitted to us within 17 months, i.e., by June 1, 2007. For 
States with a NO_X SIP Call compliance date of

[[Page 32724]]

2007, the first 3-year cycle inventory will be for 2008. Subsequent 3-
year cycle inventories will be due 17 months following the end of the 
reporting year.
    (3) States subject to Sec. Sec.  51.123 and 51.125 must report 
ozone season emissions of NO_X and summer daily emissions of 
VOC and NO_X from all point sources, non-point sources, 
onroad mobile sources, and nonroad mobile sources. The first 3-year 
cycle inventory will be for the year 2008 and must be submitted to us 
within 17 months, i.e., by June 1, 2010. Subsequent 3-year cycle 
inventories will be due 17 months following the end of the reporting 
year. This requirement does not apply to any State subject to Sec.  
51.123 solely because of its contribution to PM_2.5 
nonattainment in another State.
    (4) Any State with an area for which EPA has made an 8-hour ozone 
nonattainment designation finding (regardless of whether that finding 
has reached its effective date) must report summer daily emissions of 
VOC and NO_X from all point sources, non-point sources, 
onroad mobile sources, and nonroad mobile sources. The first 3-year 
cycle inventory will be for the year 2005 and must be submitted to us 
within 17 months, i.e., by June 1, 2007. Subsequent 3-year cycle 
inventories will be due 17 months following the end of the reporting year.

Sec.  51.35  How can my State equalize the emissions inventory effort 
from year to year?

    (a) Compiling a 3-year cycle inventory means much more effort every 
3 years. As an option, your State may ease this workload spike by using 
the following approach:
    (1) Each year, collect and report data for all Type A (large) point 
sources (This is required for all Type A point sources).
    (2) Each year, collect data for one-third of your smaller point 
sources. Collect data for a different third of these sources each year 
so that data has been collected for all of the smaller point sources by 
the end of each 3-year cycle. You must save 3 years of data and then 
report all of the smaller point sources on the 3-year cycle due date.
    (3) Each year, collect data for one-third of the area, nonroad 
mobile, and onroad mobile sources. You must save 3 years of data and 
then report all of these data on the 3-year cycle due date.
    (b) For the sources described in paragraph (a) of this section, 
your State will therefore have data from 3 successive years at any 
given time, rather than from the single year in which it is compiled.
    (c) If your State chooses the method of inventorying one-third of 
your smaller point sources and 3-year cycle area, nonroad mobile, 
onroad mobile sources each year, your State must compile each year of 
the 3-year period identically. For example, if a process hasn't changed 
for a source category or individual plant, your State must use the same 
emission factors to calculate emissions for each year of the 3-year 
period. If your State has revised emission factors during the 3 years 
for a process that hasn't changed, resubmit previous year's data using 
the revised factor. If your State uses models to estimate emissions, 
you must make sure that the model is the same for all three years.
    (d) If your State needs a new reference year emission inventory for 
a selected pollutant, your State can not use these optional reporting 
frequencies for the new reference year.
    (e) If your State is a NO_X SIP Call State, you can not 
use these optional reporting frequencies for NO_X SIP Call 
reporting.

Sec.  51.40  In what form and format should my State report the data to 
EPA?

    You must report your emission inventory data to us in electronic 
form. We support specific electronic data reporting formats and you are 
required to report your data in a format consistent with these. The 
term format encompasses the definition of one or more specific data 
fields for each of the data elements listed in Tables 2a, 2b, and 2c; 
allowed code values for categorical data fields; transmittal 
information; and data table relational structure. Because electronic 
reporting technology continually changes, contact the Emission Factor 
and Inventory Group (EFIG) for the latest specific formats. You can 
find information on the current formats at the following Internet 
address: http://www.epa.gov/ttn/chief/nif/index.html. You may also 
call the air emissions contact in your EPA Regional Office or our Info 
CHIEF help desk at (919) 541-1000 or e-mail to info.chief@epa.gov.

Sec.  51.45  Where should my State report the data?

    (a) Your State submits or reports data by providing it directly to 
EPA.
    (b) The latest information on data reporting procedures is 
available at the following Internet address: http://www.epa.gov/ttn/
chief. You may also call our Info CHIEF help desk at (919) 541-1000 or 
e-mail to info.chief@epa.gov.

Appendix A to Subpart A of Part 51--Tables and Definitions

Table 1.--Emission Thresholds by Pollutant (tpy1) for Treatment of Point
                  Sources as Type A Under Sec.   51.30
------------------------------------------------------------------------
                                            Emissions threshold for type
                 Pollutant                           A treatment
------------------------------------------------------------------------
1. SO2....................................  >=2500
2. VOC....................................  >=250
3. NOX....................................  >=2500
4. CO.....................................  >=2500
5. Pb.....................................  Does not determine Type A
                                             status
6. PM10...................................  >=250
7. PM2.5..................................  >=250
8. NH3\2\.................................  >=250
------------------------------------------------------------------------
\1\ tpy = tons per year of actual emissions.
\2\ Ammonia threshold applies only in areas where ammonia emissions are
  a factor in determining whether a source is a major source, i.e.,
  where ammonia is considered a significant precursor of PM2.5.

 Table 2a.--Data Elements for Reporting on Emissions From Point Sources,
                     Where Required by Sec.   51.30
------------------------------------------------------------------------
                                               Every-year    Three-year
                Data elements                   reporting     reporting
------------------------------------------------------------------------
1. Inventory year...........................      [check]
[check]
2. Inventory start date.....................      [check]
[check]
3. Inventory end date.......................      [check]
[check]
4. Inventory type...........................      [check]
[check]
5. FIPS code................................      [check]
[check]
6. Facility ID codes........................      [check]
[check]
7. Unit ID code.............................      [check]
[check]
8. Process ID code..........................      [check]
[check]
9. Stack ID code............................      [check]
[check]
10. Site name...............................      [check]
[check]
11. Physical address........................      [check]
[check]

[[Page 32725]]

12. SCC or PCC..............................      [check]
[check]
13. Heat content (fuel) (annual average)....      [check]
[check]
14. Heat content (fuel) (ozone season, if         [check]
[check]
 applicable)................................
15. Ash content (fuel)(annual average)......      [check]
[check]
16. Sulfur content (fuel)(annual average)...      [check]
[check]
17. Pollutant code..........................      [check]
[check]
18. Activity/throughput (for each period          [check]
[check]
 reported)..................................
19. Summer daily emissions (if applicable)..      [check]
[check]
20. Ozone season emissions (if applicable)..      [check]
[check]
21. Annual emissions........................      [check]
[check]
22. Emission factor.........................      [check]
[check]
23. Winter throughput (percent).............      [check]
[check]
24. Spring throughput (percent).............      [check]
[check]
25. Summer throughput (percent).............      [check]
[check]
26. Fall throughput (percent)...............      [check]
[check]
27. Hr/day in operation.....................      [check]
[check]
28. Start time (hour).......................      [check]
[check]
29. Day/wk in operation.....................      [check]
[check]
30. Wk/yr in operation......................      [check]
[check]
31. X stack coordinate (longitude) with                         [check]
 method accuracy descriptions...............
32. Y stack coordinate (latitude) with                          [check]
 method accuracy descriptions...............
33. Stack height............................                    [check]
34. Stack diameter..........................                    [check]
35. Exit gas temperature....................                    [check]
36. Exit gas velocity.......................                    [check]
37. Exit gas flow rate......................                    [check]
38. SIC/NAICS and at the facility and unit                      [check]
 levels.....................................
39. Design capacity (including boiler                           [check]
 capacity if applicable)....................
40. Maximum generator nameplate capacity....                    [check]
41. Primary capture and control efficiencies                    [check]
 (percent)..................................
42. Total capture and control efficiency                        [check]
 (percent)..................................
43. Control device type.....................                    [check]
44. Rule effectiveness (percent)............                    [check]
------------------------------------------------------------------------


   Table 2b.--Data Elements for Reporting on Emissions From Non-Point
   Sources and Nonroad Mobile Sources, Where Required by Sec.   51.30
------------------------------------------------------------------------
                                               Every-year    Three-year
                Data elements                   reporting     reporting
------------------------------------------------------------------------
1. Inventory year...........................      [check]
[check]
2. Inventory start date.....................      [check]
[check]
3. Inventory end date.......................      [check]
[check]
4. Inventory type...........................      [check]
[check]
5. FIPS code................................      [check]
[check]
6. SCC or PCC...............................      [check]
[check]
7. Emission factor..........................      [check]
[check]
8. Activity/throughput level (for each            [check]
[check]
 period reported)...........................
9. Total capture/control efficiency               [check]
[check]
 (percent)..................................
10. Rule effectiveness (percent)............      [check]
[check]
11. Rule penetration (percent)..............      [check]
[check]
12. Pollutant code..........................      [check]
[check]
13. Ozone season emissions (if applicable)..      [check]
[check]
14. Summer daily emissions (if applicable)..      [check]
[check]
15. Annual emissions........................      [check]
[check]
16. Winter throughput (percent).............      [check]
[check]
17. Spring throughput (percent).............      [check]
[check]
18. Summer throughput (percent).............      [check]
[check]
19. Fall throughput (percent)...............      [check]
[check]
20. Hrs/day in operation....................      [check]
[check]
21. Days/wk in operation....................      [check]
[check]
22. Wks/yr in operation.....................      [check]
[check]
------------------------------------------------------------------------

[[Page 32726]]

 Table 2c.--Data Elements for Reporting on Emissions From Onroad Mobile
                 Sources, Where Required by Sec.   51.30
------------------------------------------------------------------------
                                               Every-year    Three-year
                Data elements                   reporting     reporting
------------------------------------------------------------------------
1. Inventory year...........................      [check]
[check]
2. Inventory start date.....................      [check]
[check]
3. Inventory end date.......................      [check]
[check]
4. Inventory type...........................      [check]
[check]
5. FIPS code................................      [check]
[check]
6. SCC or PCC...............................      [check]
[check]
7. Emission factor..........................      [check]
[check]
8. Activity (VMT by SCC)....................      [check]
[check]
9. Pollutant code...........................      [check]
[check]
10. Ozone season emissions (if applicable)..      [check]
[check]
11. Summer daily emissions (if applicable)..      [check]
[check]
12. Annual emissions........................      [check]
[check]
13. Winter throughput (percent).............      [check]
[check]
14. Spring throughput (percent).............      [check]
[check]
15. Summer throughput (percent).............      [check]
[check]
16. Fall throughput (percent)...............      [check]
[check]
------------------------------------------------------------------------

Definitions
    Activity throughput--A measurable factor or parameter that relates 
directly or indirectly to the emissions of an air pollution source 
during the period for which emissions are reported. Depending on the 
type of source category, activity information may refer to the amount 
of fuel combusted, raw material processed, product manufactured, or 
material handled or processed. It may also refer to population, 
employment, or number of units. Activity information is typically the 
value that is multiplied against an emission factor to generate an 
emissions estimate.
    Annual emissions--Actual emissions for a plant, point, or process--
measured or calculated that represent a calendar year.
    Ash content--Inert residual portion of a fuel.
    Biogenic sources--Biogenic emissions are all pollutants emitted 
from non-anthropogenic sources. Example sources include trees and 
vegetation, oil and gas seeps, and microbial activity.
    Control device type--The name of the type of control device (e.g., 
wet scrubber, flaring, or process change).
    Day/wk in operations--Days per week that the emitting process 
operates--average over the inventory period.
    Design capacity--A measure of the size of a point source, based on 
the reported maximum continuous throughput or output capacity of the 
unit. For a boiler, design capacity is based on the reported maximum 
continuous steam flow, usually in units of million BTU per hour.
    Emission factor--Ratio relating emissions of a specific pollutant 
to an activity or material throughput level.
    Exit gas flow rate--Numeric value of stack gas's flow rate.
    Exit gas temperature--Numeric value of an exit gas stream's 
temperature.
    Exit gas velocity--Numeric value of an exit gas stream's velocity.
    Facility ID codes--Unique codes for a plant or facility treated as 
a point source, containing one or more pollutant-emitting units. The 
EPA's reporting format for a given reporting year may require several 
facility ID codes to ensure proper matching between data bases, e.g., 
the State's own current and most recent facility ID codes, the EPA-
assigned facility ID codes, and the ORIS (Department of Energy) ID code 
if applicable.
    Fall throughput (percent)--Part of the throughput for the three 
Fall months (September, October, November). This expresses part of the 
annual activity information based on four seasons--typically spring, 
summer, fall, and winter. It can be a percentage of the annual activity 
(e.g., production in summer is 40 percent of the year's production) or 
units of the activity (e.g., out of 600 units produced, spring = 150 
units, summer = 250 units, fall = 150 units, and winter = 50 units).
    FIPS Code--Federal Information Placement System (FIPS)is the system 
of unique numeric codes the government developed to identify States, 
counties and parishes for the entire United States, Puerto Rico, and 
Guam.
    Heat content--The amount of thermal heat energy in a solid, liquid, 
or gaseous fuel, averaged over the period for which emissions are 
reported. Fuel heat content is typically expressed in units of Btu/lb 
of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
    Hr/day in operations--Hours per day that the emitting process 
operates--average over the inventory period.
    Inventory end date--Last day of the inventory period.
    Inventory start date--First day of the inventory period.
    Inventory type--A code indicating whether the inventory submission 
includes emissions of hazardous air pollutants.
    Inventory year--The calendar year for which you calculated 
emissions estimates.
    Lead (Pb)--As defined in 40 CFR 50.12, lead should be reported as 
elemental lead and its compounds.
    Maximum nameplate capacity--A measure of the size of a generator 
which is put on the unit's nameplate by the manufacturer. The data 
element is reported in megawatts or kilowatts.
    Mobile source--A motor vehicle, nonroad engine or nonroad vehicle, 
where:
    A ``motor vehicle'' is any self-propelled vehicle used to carry 
people or property on a street or highway.
    A ``nonroad engine'' is an internal combustion engine (including 
fuel system) that is not used in a motor vehicle or vehicle only used 
for competition, or that is not affected by Sec. Sec.  111 or 202 of 
the CAA.
    A ``nonroad vehicle'' is a vehicle that is run by a nonroad engine 
and that is not a motor vehicle or a vehicle only used for competition.
    Nitrogen oxides (NO_X)--The EPA has defined nitrogen 
oxides (NO_X) in 40 CFR part 60.2 as all oxides of nitrogen 
except N₂O. Nitrogen Oxides should be reported on an 
equivalent molecular weight basis as nitrogen dioxide (NO₂).
    Non-point sources--Non-point sources collectively represent

[[Page 32727]]

individual sources that have not been inventoried as specific point, 
mobile, or biogenic sources. These individual sources treated 
collectively as non-point sources are typically too small, numerous, or 
difficult to inventory using the methods for the other classes of sources.
    Ozone Season--The period May 1 through September 30 of a year.
    PM (Particulate Matter)--Particulate matter is a criteria air 
pollutant. For the purpose of this subpart, the following definitions 
apply:
    (1) Filterable PM_2.5 or Filterable PM₁₀: 
Particles that are directly emitted by a source as a solid or liquid at 
stack or release conditions and captured on the filter of a stack test 
train. Filterable PM_2.5 is particulate matter with an 
aerodynamic diameter equal to or less than 2.5 micrometers. Filterable 
PM₁₀ is particulate matter with an aerodynamic diameter 
equal to or less than 10 micrometers.
    (2) Condensible PM: Material that is vapor phase at stack 
conditions, but which condenses and/or reacts upon cooling and dilution 
in the ambient air to form solid or liquid PM immediately after 
discharge from the stack. Note that all condensible PM, if present from 
a source, is typically in the PM_2.5 size fraction, and 
therefore all of it is a component of both primary PM_2.5 and 
primary PM₁₀.
    (3) Primary PM_2.5: The sum of filterable 
PM_2.5 and condensible PM.
    (4) Primary PM₁₀: The sum of filterable PM₁₀ 
and condensible PM.
    (5) Secondary PM: Particles that form or grow in mass through 
chemical reactions in the ambient air well after dilution and 
condensation have occurred. Secondary PM is usually formed at some 
distance downwind from the source. Secondary PM should not be reported 
in the emission inventory and is not covered by this subpart.
    PCC--Process classification code. A process-level code that 
describes the equipment or operation which is emitting pollutants. This 
code is being considered as a replacement for the SCC.
    Physical address--Street address of a facility. This is the address 
of the location where the emissions occur; not, for example, the 
corporate headquarters.
    Point source--Point sources are large, stationary (non-mobile), 
identifiable sources of emissions that release pollutants into the 
atmosphere. As used in this rule, a point source is defined as a 
facility that is a major source under Sec.  302 or part D of title I of 
the Clean Air Act. Emissions of hazardous air pollutants are not 
considered in determining whether a source is a point source under this 
subpart.
    Pollutant code--A unique code for each reported pollutant assigned 
by the reporting format specified by EPA for each reporting year.
    Primary capture and control efficiencies (percent)--Two values 
indicating the emissions capture efficiency and the emission reduction 
efficiency of a primary control device. Capture and control 
efficiencies are usually expressed as a percentage or in tenths.
    Process ID code--Unique code for the process generating the 
emissions, typically a description of a process.
    Roadway class--A classification system developed by the Federal 
Highway Administration that defines all public roadways as to type 
based on land use and physical characteristics of the roadway.
    Rule effectiveness (RE)--How well a regulatory program achieves all 
possible emission reductions. This rating reflects the assumption that 
controls typically are not 100 percent effective because of equipment 
downtime, upsets, decreases in control efficiencies, and other 
deficiencies in emission estimates. RE adjusts the control efficiency.
    Rule penetration--The percentage of a non-point source category 
covered by an applicable regulation.
    SCC--Source classification code. A process-level code that 
describes the equipment and/or operation which is emitting pollutants.
    SIC/NAICS--Standard Industrial Classification code. NAICS (North 
American Industry Classification System) codes will replace SIC codes. 
U.S. Department of Commerce's code for businesses by products or services.
    Site name--The name of the facility.
    Spring throughput (percent)--Part of throughput or activity for the 
three spring months (March, April, May). See the definition of Fall 
Throughput.
    Stack diameter--A stack's inner physical diameter.
    Stack height--A stack's physical height above the surrounding terrain.
    Stack ID code--Unique code for the point where emissions from one 
or more processes release into the atmosphere.
    Start time (hour)--Start time (if available) that was applicable 
and used for calculations of emissions estimates.
    Sulfur content--Sulfur content of a fuel, usually expressed as 
percent by weight.
    Summer daily emissions--Average day's emissions for a typical 
summer day with conditions critical to ozone attainment planning. The 
State will select the particular month(s) in summer and the day(s) in 
the week to be represented. The selection of conditions should be 
coordinated with the conditions assumed in the development of 
reasonable further progress plans, rate of progress plans and 
demonstrations, and/or emissions budgets for transportation conformity, 
to allow comparability of daily emission estimates.
    Summer throughput (percent)--Part of throughput or activity for the 
three summer months (June, July, August). See the definition of Fall 
Throughput.
    Total capture and control efficiency (percent)--The net emission 
reduction efficiency of all emissions collection and devices.
    Type A source--Large point sources with actual annual emissions 
greater than or equal to any of the emission thresholds listed in Table 
1 for Type A sources.
    Unit ID code--Unique code for the unit of generation of emissions, 
typically a physical piece or closely related set of equipment. The 
EPA's reporting format for a given reporting year may require multiple 
unit ID codes to ensure proper matching between data bases, e.g., the 
State's own current and most recent unit ID codes, the EPA-assigned 
unit ID codes if any, and the ORIS (Department of Energy) ID code if 
applicable.
    VMT by SCC--Vehicle miles traveled (VMT) disaggregated to the SCC 
level, i.e., reflecting combinations of vehicle type and roadway class. 
VMT expresses vehicle activity and is used with emission factors. The 
emission factors are usually expressed in terms of grams per mile of 
travel. Because VMT does not correlate directly to emissions that occur 
while the vehicle isn't moving, these nonmoving emissions are 
incorporated into the emission factors in EPA's MOBILE Model.
    VOC--Volatile Organic Compounds. The EPA's regulatory definition of 
VOC is in 40 CFR 51.100.
    Winter throughput (percent)--Part of throughput or activity for the 
three winter months (December, January, February, all from the same 
year, e.g., Winter 2000 = January 2000 + February, 2000 + December 
2000). See the definition of Fall Throughput.
    Wk/yr in operation--Weeks per year that the emitting process operates.
    X stack coordinate (longitude)--An object's east-west geographical 
coordinate.
    Y stack coordinate (latitude)--An object's north-south geographical 
coordinate.

[[Page 32728]]

Appendix B to Subpart A of Part 51--[Reserved]

    3. Part 51 is amended by revising Sec.  51.122 of subpart G to read 
as follows:

Sec.  51.122  Emissions reporting requirements for SIP revisions 
relating to budgets for NOX emissions.

    (a) For its transport SIP revision under Sec.  51.121 of this part, 
each State must submit to EPA NO_X emissions data as 
described in this section.
    (b) Each revision must provide for periodic reporting by the State 
of NO_X emissions data to demonstrate whether the State's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) Every-year reporting cycle. Each revision must provide for 
reporting of NO_X emissions data every year as follows:
    (i) The State must report to EPA emissions data from all 
NO_X sources within the State for which the State specified 
control measures in its SIP submission under Sec.  51.121(g) of this 
part. This would include all sources for which the State has adopted 
measures that differ from the measures incorporated into the baseline 
inventory for the year 2007 that the State developed in accordance with 
Sec.  51.121(g) of this part.
    (ii) If sources report NO_X emissions data to EPA for a 
given year pursuant to a trading program approved under Sec.  51.121(p) 
of this part or pursuant to the monitoring and reporting requirements 
of subpart H of 40 CFR part 75, then the State need not provide an 
every-year cycle report to EPA for such sources.
    (2) Three-year cycle reporting. Each plan must provide for 
triennial (i.e., every third year) reporting of NO_X 
emissions data from all sources within the State.
    (3) The data availability requirements in Sec.  51.116 of this part 
must be followed for all data submitted to meet the requirements of 
paragraphs (b)(1) and (2) of this section.
    (c) The data reported in paragraph (b) of this section must meet 
the requirements of subpart A of this part.
    (d) Approval of ozone season calculation by EPA. Each State must 
submit for EPA approval an example of the calculation procedure used to 
calculate ozone season emissions along with sufficient information to 
verify the calculated value of ozone season emissions.
    (e) Reporting schedules.
    (1) Data collection is to begin during the ozone season one year 
prior to the State's NO_X SIP Call compliance date.
    (2) Reports are to be submitted according to paragraph (b) of this 
section and the schedule in Table 1. After 2008, triennial reports are 
to be submitted every third year and annual reports are to be submitted 
each year that a triennial report is not required.

                Table 1.--Schedule for Submitting Reports
------------------------------------------------------------------------
           Data collection year                Type of report required
------------------------------------------------------------------------
2002......................................  Triennial.
2003......................................  Annual.
2004......................................  Annual.
2005......................................  Triennial.
2006......................................  Annual.
2007......................................  Annual.
2008......................................  Triennial.
------------------------------------------------------------------------

    (3) States must submit data for a required year no later than 17 
months after the end of the calendar year for which the data are 
collected.
    (f) Data reporting procedures are given in subpart A. When 
submitting a formal NO_X Budget Emissions Report and 
associated data, States shall notify the appropriate EPA Regional Office.
    (g) Definitions. As used in this section, words and terms shall 
have the meanings set forth in appendix A of subpart A of this part.
    4. Part 51 is amended by adding Sec.  51.123 to Subpart G to read 
as follows:

Sec.  51.123  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of oxides of 
nitrogen pursuant to the Clean Air Interstate Rule.

    (a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c) of 
this section must submit a SIP revision to comply with the requirements 
of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NO_X 
in amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the fine particles (PM_2.5) and/or the 8-hour ozone NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) will contain adequate 
provisions, for purposes of complying with Sec.  110(a)(2)(D)(i)(I) of 
the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision 
contains measures that assure compliance with the applicable 
requirements of this section.
    (c) The following States are subject to the requirements of this 
section: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, 
Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, 
Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, 
New York, North Carolina, Ohio, Pennsylvania, South Carolina, 
Tennessee, Texas, Virginia, West Virginia, Wisconsin, and the District 
of Columbia, provided that Connecticut shall be subject to a seasonal 
NO_X reduction requirement, unless it adopts an annual 
NO_X reduction requirement, as described in paragraph (q) of 
this section.
    (d)(1) The SIP submissions required under paragraph (a) of this 
section must be submitted to EPA by no later than 18 months from the 
date of promulgation of the final Clean Air Interstate Rule.
    (2) The requirements of appendix V shall apply to the SIP 
submissions required under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision to the 
appropriate Regional Office, with a letter giving notice of such action.
    (e)(1)(i) The Annual EGU NO_X budget for a State is 
defined as the total amount of NO_X emissions from all EGUs 
in that State for a year if the State meets the requirements of 
paragraph (a) of this section by imposing control measures, at least in 
part, on EGUs. If a State imposes control measures under this section 
on only EGUs, the Annual EGU NO_X budget amounts for a State 
shall not exceed the amounts, during the indicated periods, specified 
in paragraph (e)(2) of this section.
    (ii) The Non-EGU Reduction Requirement is defined as the amount of 
NO_X emission reductions the State demonstrates, in 
accordance with paragraph (g) of this section, it will achieve from 
non-EGUs during the appropriate period. If a State meets the 
requirements of paragraph (a) of this section by imposing control 
measures on only non-EGUs, the State's Non-EGU Reduction Requirement 
shall equal or exceed the amount specified in paragraph (e)(3) of this 
section.
    (iii) If a State meets the requirements of paragraph (a) of this 
section by imposing control measures on both EGUs and non-EGUs, the 
amount of the Non-EGU Reduction Requirement shall equal or exceed the 
difference between the amount of the State's Annual EGU NO_X 
budget specified in paragraph (e)(2) of this section and the amount of 
the State's Annual EGU NO_X budget specified in the SIP for 
the appropriate period.

[[Page 32729]]

    (2) For a State that complies with the requirements of paragraph 
(a) of this section by imposing control measures only on EGUs, the 
amount of the Annual EGU NO_X budget, in tons per year, shall 
be as follows, for the indicated State, for the indicated period:

------------------------------------------------------------------------
                                          Annual EGU NOX  Annual EGU NOX
                  State                    budget, 2010    budget, 2015
                                           through 2014     and beyond
------------------------------------------------------------------------
Alabama.................................          67,422          56,185
Arkansas................................          24,919          20,765
Delaware................................           5,089           4,241
District of Columbia....................             215             179
Florida.................................         115,503          96,253
Georgia.................................          63,575          52,979
Illinois................................          73,622          61,352
Indiana.................................         102,295          85,246
Iowa....................................          30,458          25,381
Kansas..................................          32,436          27,030
Kentucky................................          77,938          64,948
Louisiana...............................          47,339          39,449
Maryland................................          26,607          22,173
Massachusetts...........................          19,630          16,358
Michigan................................          60,212          50,177
Minnesota...............................          29,303          24,420
Mississippi.............................          21,932          18,277
Missouri................................          56,571          47,143
New Jersey..............................           9,895           8,246
New York................................          52,503          43,753
North Carolina..........................          55,763          46,469
Ohio....................................         101,704          84,753
Pennsylvania............................          84,552          70,460
South Carolina..........................          30,895          25,746
Tennessee...............................          47,739          39,783
Texas...................................         224,314         186,928
Virginia................................          31,087          25,906
West Virginia...........................          68,235          56,863
Wisconsin...............................          39,044          32,537
                                         -----------------
    Total...............................       1,600,799       1,333,999
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph 
(a) of this section by imposing control measures on only non-EGUs, the 
amount of the Non-EGU Reduction Requirement, in tons per year, shall be 
as follows, for the indicated State, for the indicated period:

------------------------------------------------------------------------
                                              Non-EGU         Non-EGU
                                             reduction       reduction
                  State                    requirement,    requirement,
                                           2010 through      2015 and
                                             2014 \1\       beyond \2\
------------------------------------------------------------------------
Alabama.................................          66,678          72,415
Arkansas................................          27,581          32,035
Delaware................................           5,211           6,559
District of Columbia....................               0               0
Florida.................................          46,097          74,247
Georgia.................................          87,025         100,321
Illinois................................          96,778         117,148
Indiana.................................         133,705         156,754
Iowa....................................          51,642          61,219
Kansas..................................          68,464          74,870
Kentucky................................         115,962         133,752
Louisiana...............................           2,361          10,651
Maryland................................          33,793          39,727
Massachusetts...........................               0               0
Michigan................................          60,688          76,323
Minnesota...............................          71,697          80,280
Mississippi.............................          21,168          26,623
Missouri................................          76,229          93,657
New Jersey..............................          19,105          22,154
New York................................          11,497          21,747
North Carolina..........................           5,237          15,931
Ohio....................................         159,696         171,147
Pennsylvania............................         123,148         142,440

[[Page 32730]]

South Carolina..........................          33,805          40,454
Tennessee...............................          55,061          62,917
Texas...................................               0          13,572
Virginia................................          23,813          31,394
West Virginia...........................          86,965          91,337
Wisconsin...............................          66,456          64,863
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.

    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) Should a State elect to impose control measures on EGUs, 
then those measures must impose a NO_X mass emissions cap on 
all such sources in the State.
    (ii) Should a State elect to impose control measures on fossil 
fuel-fired non-EGUs that are boilers or combustion turbines with a 
maximum design heat input greater than 250 mmBtu/hr, then those 
measures must impose a NO_X mass emissions cap on all such 
sources in the State.
    (iii) Should a State elect to impose control measures on fossil 
fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii) 
of this section, then those measures must impose a NO_X mass 
emissions cap on all such sources in the State, or the State must 
demonstrate why such emissions cap is not practicable, and adopt 
alternative requirements that ensure to the maximum practicable degree 
that the State will comply with its requirements under paragraph (e) of 
this section, as applicable, in 2010 and subsequent years. (g)(1) Each 
SIP revision which includes control measures covering non-EGUs as part 
or all of a State's obligation in meeting its requirement under 
paragraph (a) of this section must demonstrate that such control 
measures are adequate to provide for the timely compliance with the 
State's Non-EGU Reduction Requirement under paragraph (e) of this 
section, and are not otherwise required under the Clean Air Act.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP requires controls:
    (i) A detailed historical baseline inventory of NO_X mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP submission.
    (A) This inventory must represent estimates of actual emissions 
based on part 75 monitoring data, if the source category is subject to 
part 75 monitoring requirements.
    (B) In the absence of part 75 monitoring data, actual emissions 
must be estimated using assumptions that ensure a source or source 
category's actual emissions are not overestimated, and must include 
source-specific or category-specific data. If a State uses factors to 
estimate emissions, production or utilization, or effectiveness of 
controls or rules for a source category, such factors must be chosen to 
ensure that emissions are not overestimated, or the State must justify 
the use of another value with additional information showing with 
reasonable confidence that the substitute value is more appropriate for 
estimating actual emissions.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development, and must be consistent with the 
planning assumptions regarding vehicle miles traveled and other factors 
current at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates must be based on the emission 
methodologies recommended in EPA guidance current at the time of the 
SIP development or the SIP must document that another method is 
superior due to local factors.
    (ii) A detailed baseline inventory of NO_X mass emissions 
from the source category in the years 2010 and 2015, absent the control 
measures specified in the SIP submission, and reflecting changes in 
these emissions from the historical baseline year to the years 2010 and 
2015, based on projected changes in the production input and/or output, 
population, vehicle miles traveled, economic activity or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any rules 
or regulations that will affect NO_X emissions from this 
source category, excluding any control measures specified in the SIP 
submission to meet the NO_X emissions reduction requirements 
of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category, and must be consistent with both national projections 
and relevant official planning assumptions including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are themselves 
inconsistent with official U.S. Census projections of population and 
energy consumption projections contained in the Annual Energy Outlook 
published by the U.S. Department of Energy, adjustments must be made to 
correct the inconsistency, or the SIP must demonstrate how the official 
planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2010 or 2015, as appropriate.
    (iii) A projection of NO_X mass emissions in 2010 and 
2015 from the source category identified in paragraph (g)(2)(i) of this 
section resulting from implementation of each of the control

[[Page 32731]]

measures specified in the SIP submission.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production and emissions to shift to 
non-regulated or less stringently regulated sources in the source 
category in the same or another State, and must include in the 
projected emissions inventory any such amounts of emissions that may 
shift to other sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2010 and 2015 NO_X emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
for 2010 and 2015, respectively, from the lower of the amounts in 
paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015, 
respectively, may be credited towards the State's Non-EGU Reduction 
Requirement in paragraph (e)(3) of this section for the appropriate 
period.
    (v) Each revision must identify the sources of the data used in the 
estimate and projection of emissions.
    (h) Each revision must comply with Sec.  51.116 (regarding data 
availability).
    (i) Each revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section. Specifically, the 
revision must meet the following requirements:
    (1) The revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of NO_X emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable 
portions of the control measures;
    (2) The revision must comply with Sec.  51.212 (regarding testing, 
inspection, enforcement, and complaints);
    (3) If the revision contains any transportation control measures, 
then the revision must comply with Sec.  51.213 (regarding 
transportation control measures);
    (4)(i) If the revision contains measures to control EGUs, then the 
revision must require such sources to comply with the monitoring and 
reporting provisions of subpart H of part 75.
    (ii) If the revision contains measures to control fossil fuel-fired 
non-EGUs that are boilers or combustion turbines with a maximum design 
heat input greater than 250 mmBtu/hr, then the revision must require 
such sources to comply with the monitoring and reporting provisions of 
subpart H of part 75.
    (iii) If the revision contains measures to control any other non-
EGUs that are not described in paragraph (i)(4)(ii) of this section, 
the revision must require such sources to comply with the monitoring 
and reporting provisions of subpart H of part 75, or the State must 
demonstrate why such requirements are not practicable, and adopt 
alternative requirements that ensure to the maximum practicable degree 
that the required emissions reductions will be achieved.
    (j) Each revision must show that the State has legal authority to 
carry out the revision, including authority to:
    (1) Adopt emissions standards and limitations and any other 
measures necessary for attainment and maintenance of the State's 
relevant Annual EGU NO_X budget or the Non-EGU Reduction 
Requirement, as applicable, under paragraph (e);
    (2) Enforce applicable laws, regulations, and standards, and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to 
install, maintain, and use emissions monitoring devices and to make 
periodic reports to the State on the nature and amounts of emissions 
from such stationary sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public as reported and as correlated with any 
applicable emissions standards or limitations.
    (k)(1) The provisions of law or regulation which the State 
determines provide the authorities required under this section must be 
specifically identified, and copies of such laws or regulations must be 
submitted with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under Sec.  114 of the CAA.
    (l)(1) A revision may assign legal authority to local agencies in 
accordance with Sec.  51.232.
    (2) Each revision must comply with Sec.  51.240 (regarding general 
plan requirements).
    (m) Each revision must comply with Sec.  51.280 (regarding resources).
    (n) Each revision must provide for State compliance with the 
reporting requirements set forth in Sec.  51.125.
    (o)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AA through 
HH of part 96 of this chapter, (the model CAIR NO_X trading 
program), incorporates such part by reference into its regulations, or 
adopts regulations that differ substantively from such part only as set 
forth in paragraph (o)(2) of this section, then that portion of the 
State's SIP revision is automatically approved as meeting the 
requirement of paragraph (e)(1)(i) of this section, provided that the 
State has the legal authority to take such action and to implement its 
responsibilities under such regulations.
    (2)(i) If a State adopts an emissions trading program that differs 
substantively from subparts AA through HH of part 96 of this chapter 
only as described in paragraph (o)(2)(ii) of this section, then the 
emissions trading program is approved as set forth in paragraph (o)(1) 
of this section.
    (ii) The State may decline to adopt the allocation provisions set 
forth in subpart EE of part 96 of this chapter and may instead adopt 
any methodology for allocating NO_X allowances to individual 
sources, provided that:
    (A) The State's methodology does not allow the State to allocate 
NO_X allowances in excess of the total amount of 
NO_X emissions which the State has assigned to its trading 
program; and
    (B) The State's methodology conforms with the timing requirements 
for submission of allocations to the Administrator set forth in Sec.  
96.141 of this chapter.
    (3) If a State adopts an emissions trading program that differs 
substantively from subparts AA through HH of part 96 of this chapter, 
other than as set forth in paragraph (o)(2)(ii) of this section, then 
such portion of the trading program is not automatically approved as 
set forth in paragraph (o)(1) of this section, but will be reviewed by 
the Administrator for approvability in accordance with the other 
provisions of this section.
    (p)(1) The State may revise its applicable implementation plan to 
provide that, for each year during which a State imposes controls on 
EGUs under paragraph (o) of this section, such EGUs shall not be 
subject to the requirements of the State's applicable implementation 
plan that meet the requirements of

[[Page 32732]]

Sec.  51.121. The owners and operators of such EGUs shall surrender for 
deduction by the Administrator any NO_X SIP Call allowances 
allocated to such units for any such year.
    (2) Notwithstanding a revision by the State authorized under 
paragraph (p)(1) of this section, a State's applicable implementation 
plan that, without such revision, imposes controls on EGUs under Sec.  
51.121 determined by the Administrator to meet the requirements of 
Sec.  51.121 shall be deemed to continue to meet the requirements of 
Sec.  51.121.(q)(1)(i) The SIP revision required under paragraph (a) of 
this section for the State of Connecticut must require emissions 
reductions during the ozone season, which begins May 1 and ends 
September 30 of any year, commencing with 2010.
    (ii) Except as provided under paragraph (q)(2) of this section, the 
Administrator shall not approve SIP provisions that adopt the model 
CAIR NO_X trading program, under subparts AA through HH of 
part 96 of this chapter.
    (iii) For purposes of determining the applicability of paragraph 
(e) of this section to the State of Connecticut's SIP revision required 
under paragraph (a) of this section--
    (A) The term ``Seasonal EGU NO_X budget'' shall replace 
the term ``Annual EGU NO_X budget;'' and
    (B) The Seasonal EGU NO_X budget, in tons per season, for 
the State of Connecticut shall be 4,360 for the years 2010 through 
2014, and 3,633 for the years 2015 and beyond; and
    (C) The amount of the Non-EGU Reduction Requirement, in tons per 
season, for the State of Connecticut shall be zero, for the years 2010 
through 2014, and zero, for the years 2015 and beyond.
    (3) In lieu of the SIP provisions required under paragraph (q)(1) 
of this section, the Administrator may approve a SIP revision adopted 
by the State of Connecticut that requires annual NO_X 
emissions reductions and that meets the requirements of this section, 
as revised by this paragraph.
    (i) For purposes of paragraph (e)(2) of this section, the Annual 
EGU NO_X budget, in tons per year, for Connecticut shall be 
9,283 for the years 2010 through 2014, and 7,735 for the years 2015 and 
beyond; and
    (ii) For purposes of paragraph (e)(3) of this section, the amount 
of the Non-EGU Reduction Requirement, in tons per year, for Connecticut 
shall be zero for the years 2010 through 2014, and zero for the years 
2015 and beyond.
    (4) The Administrator may approve a SIP revision from the State of 
Connecticut adopted under paragraph (q)(2) of this section that adopts 
the model CAIR NO_X trading program, under subparts AA 
through HH of part 96 of this chapter.
    (r) The terms used in this section shall have the following meanings:
    Boiler means an enclosed fossil-or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating 
water, steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in 
which the energy input to the unit is first used to produce useful 
thermal energy and at least some of the reject heat from the useful 
thermal energy application or process is then used for power production.
    CAIR NO_X Trading Program means a multi-State nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator in accordance with subparts AA through HH of part 
96 of this chapter and this section, as a means of mitigating 
interstate transport of fine particulates, ozone, and nitrogen oxides.
    Cogeneration unit means a unit:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after 
which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent of total energy input 
or, if useful thermal energy produced is less than 15 percent of total 
energy output, not less than 45 percent of total energy input.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.
    Combustion turbine means an enclosed device comprising a 
compressor, a combustor, and a turbine and in which the flue gas 
resulting from the combustion of fuel in the combustor passes through 
the turbine, rotating the turbine. A combustion turbine that is 
combined cycle also includes any associated heat recovery steam 
generator and steam turbine.
    Electric generating unit or EGU means:
    (1) Except for a unit under paragraph (2) of this definition, a 
fossil fuel-fired boiler or combustion turbine serving at any time a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale; or
    (2) A fossil fuel-fired cogeneration unit serving at any time a 
generator with nameplate capacity of more than 25 MWe and in any year 
supplying more than one-third of the unit's potential electric output 
capacity or 219,000 MWh, whichever is greater, to any utility power 
distribution system for sale.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, any boiler or 
turbine combusting any amount of fossil fuel.
    Generator means a device that produces electricity.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state 
basis, as specified by the manufacturer of the unit as of the initial 
installation of the unit.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means the maximum electrical generating output 
(in MWe) that a generator can sustain over a specified period of time 
when not restricted by seasonal or other deratings, as specified by the 
manufacturer of the generator as of the initial installation of the 
generator or, if the generator is subsequently modified or 
reconstructed resulting in an increase in such maximum electrical 
generating output, as specified by the person conducting the 
modification or reconstruction.
    Non-EGU means a source of NO_X emissions that is not an 
EGU.
    NO_X means oxides of nitrogen.
    NO_X Budget Trading Program means a multi-State nitrogen 
oxide air pollution control and emission reduction program established 
by air pollution control and emission reduction program established by 
the Administrator in accordance with subparts A through I of part 96 of 
this chapter and Sec.  51.121, as a means of mitigating interstate 
transport of ozone and nitrogen oxides.
    NO_X SIP Call allowance means a limited authorization 
issued by the Administrator under the NO_X Budget Trading 
Program to emit up to one ton of nitrogen oxides during the ozone 
season of the specified year or any year thereafter.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from power production in a useful thermal energy application or 
process; or

[[Page 32733]]

    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in power production.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power and 
at least some of the reject heat from the power production is then used 
to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is 
not limited to, any on-site processing or treatment of fuel combusted 
at the unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, 
excluding any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a distribution utility and 
dedicated to delivering electricity to customers.
    5. Part 51 is amended by adding Sec.  51.124 to Subpart G to read 
as follows:

Sec.  51.124  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of sulfur dioxide 
pursuant to the Clean Air Interstate Rule.

    (a) Under Sec.  110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c) of 
this section must submit a SIP revision to comply with the requirements 
of Sec.  110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), 
through the adoption of adequate provisions prohibiting sources and 
other activities from emitting SO₂ in amounts that will 
contribute significantly to nonattainment in, or interfere with 
maintenance by, one or more other States with respect to the fine 
particles (PM2.5) NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) will contain adequate 
provisions, for purposes of complying with Sec.  110(a)(2)(D)(i)(I) of 
the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision 
contains measures that assure compliance with the applicable 
requirements of this section.
    (c) The following States are subject to the requirements of this 
section: Alabama, Arkansas, Delaware, Florida, Georgia, Illinois, 
Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, 
Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North 
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 
Virginia, West Virginia, Wisconsin, and the District of Columbia.
    (d)(1) The SIP submissions required under paragraph (a) of this 
section must be submitted to EPA by no later than 18 months from the 
date of promulgation of the final Clean Air Interstate Rule.
    (2) The requirements of appendix V shall apply to the SIP 
submissions required under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision to the 
appropriate Regional Office, with a letter giving notice of such action.
    (e)(1)(i) The Annual EGU SO₂ budget for a State is 
defined as the total amount of SO₂ emissions from all EGUs 
in that State for a year if the State meets the requirements of 
paragraph (a) of this section by imposing control measures, at least in 
part, on EGUs. If a State imposes control measures under this section 
on only EGUs, the Annual EGU SO₂ budget amounts for a State 
shall not exceed the amounts, during the indicated periods, specified 
in paragraph (e)(2) of this section.
    (ii) The Non-EGU Reduction Requirement is defined as the amount of 
SO₂ emission reductions the State demonstrates, in 
accordance with paragraph (g) of this section, it will achieve from 
non-EGUs during the appropriate period. If a State meets the 
requirements of paragraph (a) of this section by imposing control 
measures on only non-EGUs, the State's Non-EGU Reduction Requirement 
shall equal or exceed the amount specified in paragraph (e)(3) of this 
section.
    (iii) If a State meets the requirements of paragraph (a) of this 
section by imposing control measures on both EGUs and non-EGUs, the 
amount of the Non-EGU Reduction Requirement shall equal or exceed the 
difference between the amount of the State's Annual EGU SO₂ 
budget specified in paragraph (e)(2) of this section and the amount of 
the State's Annual EGU SO₂ budget specified in the SIP for 
the appropriate period.
    (2) For a State that complies with the requirements of paragraph 
(a) of this section by imposing control measures only on EGUs, the 
amount of the Annual EGU SO₂ budget, in tons per year, shall 
be as follows, for the indicated State, for the indicated period:

------------------------------------------------------------------------
                                          Annual EGU SO2
                                           budget, 2010   Annual EGU SO2
                  State                    through 2014    budget, 2015
                                                \1\       and beyond \2\
------------------------------------------------------------------------
Alabama.................................         157,582         110,307
Arkansas................................          48,702          34,091
Delaware................................          22,411          15,687
District of Columbia....................             708             495
Florida.................................         253,450         177,415
Georgia.................................         213,057         149,140
Illinois................................         192,671         134,869
Indiana.................................         254,599         178,219
Iowa....................................          64,095          44,866
Kansas..................................          58,304          40,812
Kentucky................................         188,773         132,141
Louisiana...............................          59,948          41,963
Maryland................................          70,697          49,488
Massachusetts...........................          82,561          57,792

[[Page 32734]]

Michigan................................         178,605         125,024
Minnesota...............................          49,987          34,991
Mississippi.............................          33,763          23,634
Missouri................................         137,214          96,050
New Jersey..............................          32,392          22,674
New York................................         135,139          94,597
North Carolina..........................         137,342          96,139
Ohio....................................         333,520         233,464
Pennsylvania............................         275,990         193,193
South Carolina..........................          57,271          40,089
Tennessee...............................         137,216          96,051
Texas...................................         320,946         224,662
Virginia................................          63,478          44,435
West Virginia...........................         215,881         151,117
Wisconsin...............................          87,264          61,085
                                         -----------------
    Total...............................       3,863,566      2,704,490
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.

    (3) For a State that complies with the requirements of paragraph 
(a) of this section by imposing control measures on only non-EGUs, the 
amount of the Non-EGU Reduction Requirement, in tons per year, shall be 
as follows, for the indicated State, for the indicated period:

------------------------------------------------------------------------
                                              Non-EGU         Non-EGU
                                             reduction       reduction
                  State                    requirement,    requirement,
                                           2010 through      2015 and
                                             2014 \1\       beyond \2\
------------------------------------------------------------------------
Alabama.................................         157,582         204,857
Arkansas................................          48,702          63,312
Delaware................................          22,411          29,134
District of Columbia....................             708             920
Florida.................................         253,450         329,485
Georgia.................................         213,057         276,974
Illinois................................         192,671         250,472
Indiana.................................         254,599         330,978
Iowa....................................          64,095          83,323
Kansas..................................          58,304          75,795
Kentucky................................         188,773         245,405
Louisiana...............................          59,948          77,932
Maryland................................          70,697          91,906
Massachusetts...........................          82,561         107,329
Michigan................................         178,605         232,187
Minnesota...............................          49,987          64,983
Mississippi.............................          33,763          43,892
Missouri................................         137,214         178,378
New Jersey..............................          32,392          42,109
New York................................         135,139         175,681
North Carolina..........................         137,342         178,545
Ohio....................................         333,520         433,576
Pennsylvania............................         275,990         358,787
South Carolina..........................          57,271          74,452
Tennessee...............................         137,216         178,380
Texas...................................         320,946         417,230
Virginia................................          63,478          82,521
West Virginia...........................         215,881         280,645
Wisconsin...............................          87,264        113,443
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.

    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.

[[Page 32735]]

    (2)(i) Should a State elect to impose control measures on EGUs, 
then those measures must impose a SO₂ mass emissions cap on 
all such sources in the State.
    (ii) Should a State elect to impose control measures on fossil 
fuel-fired non-EGUs that are boilers or combustion turbines with a 
maximum design heat input greater than 250 mmBtu/hr, then those 
measures must impose a SO₂ mass emissions cap on all such 
sources in the State.
    (iii) Should a State elect to impose control measures on fossil 
fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii) 
of this section, then those measures must impose a SO₂ mass 
emissions cap on all such sources in the State, or the State must 
demonstrate why such emissions cap is not practicable, and adopt 
alternative requirements that ensure to the maximum practicable degree 
that the State will comply with its requirements under paragraph (e) of 
this section, as applicable, in 2010 and subsequent years.
    (g)(1) Each SIP revision which includes control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Non-EGU Reduction Requirement under paragraph (e) of 
this section, and are not otherwise required under the Clean Air Act.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP requires controls:
    (i) A detailed historical baseline inventory of SO₂ mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP submission.
    (A) This inventory must represent estimates of actual emissions 
based on part 75 monitoring data, if the source category is subject to 
part 75 monitoring requirements.
    (B) In the absence of part 75 monitoring data, actual emissions 
must be estimated using assumptions that ensure a source or source 
category's actual emissions are not overestimated, and must include 
source-specific or category-specific data. If a State uses factors to 
estimate emissions, production or utilization, or effectiveness of 
controls or rules for a source category, such factors must be chosen to 
ensure that emissions are not overestimated, or the State must justify 
the use of another value with additional information showing with 
reasonable confidence that the substitute value is more appropriate for 
estimating actual emissions.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development, and must be consistent with the 
planning assumptions regarding vehicle miles traveled and other factors 
current at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates must be based on the emission 
methodologies recommended in EPA guidance current at the time of the 
SIP development or the SIP must document that another method is 
superior due to local factors.
    (ii) A detailed baseline inventory of SO₂ mass emissions 
from the source category in the years 2010 and 2015, absent the control 
measures specified in the SIP submission, and reflecting changes in 
these emissions from the historical baseline year to the years 2010 and 
2015, based on projected changes in the production input and/or output, 
population, vehicle miles traveled, economic activity or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any rules 
or regulations that will affect SO₂ emissions from this 
source category, excluding any control measures specified in the SIP 
submission to meet the SO₂ emissions reduction requirements 
of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category, and must be consistent with both national projections 
and relevant official planning assumptions including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are themselves 
inconsistent with official U.S. Census projections of population and 
energy consumption projections contained in the Annual Energy Outlook 
published by the U.S. Department of Energy, adjustments must be made to 
correct the inconsistency, or the SIP must demonstrate how the official 
planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2010 or 2015, as appropriate.
    (iii) A projection of SO₂ mass emissions in 2010 and 
2015 from the source category identified in paragraph (g)(2)(i) of this 
section resulting from implementation of each of the control measures 
specified in the SIP submission.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production and emissions to shift to 
non-regulated or less stringently regulated sources in the source 
category in the same or another State, and must include in the 
projected emissions inventory any such amounts of emissions that may 
shift to other sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2010 and 2015 SO₂ emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
for 2010 and 2015, respectively, from the lower of the amounts in 
paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015, 
respectively, may be credited towards the State's Non-EGU Reduction 
Requirement in paragraph (e)(3) of this section for the appropriate 
period.
    (v) Each revision must identify the sources of the data used in the 
estimate and projection of emissions.
    (h) Each revision must comply with Sec.  51.116 (regarding data 
availability).
    (i) Each revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section. Specifically, the 
revision must meet the following requirements:
    (1) The revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of SO₂ emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable 
portions of the control measures;
    (2) The revision must comply with Sec.  51.212 (regarding testing, 
inspection, enforcement, and complaints);
    (3) If the revision contains any transportation control measures, 
then the revision must comply with Sec.  51.213

[[Page 32736]]

(regarding transportation control measures);
    (4)(i) If the revision contains measures to control EGUs, then the 
revision must require such sources to comply with the monitoring and 
reporting provisions of part 75.
    (ii) If the revision contains measures to control fossil fuel-fired 
non-EGUs that are boilers or combustion turbines with a maximum design 
heat input greater than 250 mmBtu/hr, then the revision must require 
such sources to comply with the monitoring and reporting provisions of 
part 75.
    (iii) If the revision contains measures to control any other non-
EGUs that are not described in paragraph (i)(4)(ii) of this section, 
the revision must require such sources to comply with the monitoring 
and reporting provisions of part 75, or the State must demonstrate why 
such requirements are not practicable, and adopt alternative 
requirements that ensure to the maximum practicable degree that the 
required emissions reductions will be achieved.
    (j) Each revision must show that the State has legal authority to 
carry out the revision, including authority to:
    (1) Adopt emissions standards and limitations and any other 
measures necessary for attainment and maintenance of the State's 
relevant Annual EGU SO₂ budget or the Non-EGU Reduction 
Requirement, as applicable, under paragraph (e);
    (2) Enforce applicable laws, regulations, and standards, and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to 
install, maintain, and use emissions monitoring devices and to make 
periodic reports to the State on the nature and amounts of emissions 
from such stationary sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public as reported and as correlated with any 
applicable emissions standards or limitations.
    (k)(1) The provisions of law or regulation which the State 
determines provide the authorities required under this section must be 
specifically identified, and copies of such laws or regulations must be 
submitted with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under Sec.  114 of the CAA. (l)(1) A revision may assign legal 
authority to local agencies in accordance with Sec.  51.232.
    (2) Each revision must comply with Sec.  51.240 (regarding general 
plan requirements).
    (m) Each revision must comply with Sec.  51.280 (regarding 
resources).
    (n) Each revision must provide for State compliance with the 
reporting requirements set forth in Sec.  51.125.
    (o) Notwithstanding any other provision of this section, if a State 
adopts regulations substantively identical to subparts AAA through HHH 
of part 96 of this chapter (CAIR SO₂ Emissions Trading 
Program), or incorporates such part by reference into its regulations, 
then that portion of the State's SIP revision is automatically approved 
as meeting the requirements of paragraph (e)(1)(i) of this section, 
provided that the State has the legal authority to take such action and 
to implement its responsibilities under such regulations.
    (p) For a State that does not adopt regulations in accordance with 
paragraph (o) of this section:
    (1) The sources subject to the Acid Rain Program , in addition to 
complying with the requirements of Sec.  72.9(c)(1)(i) of this chapter, 
shall hold the following amounts of Acid Rain allowances, as of the 
allowance transfer deadline in the source's compliance account--
    (i) For each Acid Rain allowance allocated for a year during 2010 
through 2014 that is held in order to meet the requirements of Sec.  
72.9(c)(1)(i) of this chapter, one additional Acid Rain allowance 
allocated for a year during 2010 through 2014; and
    (ii) For each Acid Rain allowance allocated for a year during 2015 
or thereafter held in accordance with Sec.  72.9(c)(1)(i) of this 
chapter, two additional Acid Rain allowances allocated for a year 
during 2015 or thereafter.
    (2) When the Administrator deducts Acid Rain allowances under Sec.  
73.35(b) and (c) of this chapter, the Administrator will also deduct 
from the source's compliance account the amount of Acid Rain allowances 
required to be held under paragraph (p)(1) of this section. If the 
owner and operator of the source fails to hold the Acid Rain allowances 
required under paragraph (p)(1) of this section, then, for each Acid 
Rain allowance required but not held, the Administrator will deduct 
from such compliance account three Acid Rain allowances allocated for 
the year after the year of the allowance transfer deadline by which the 
Acid Rain allowances were required to be held.
    (q) The terms used in this section shall have the following 
meanings:
    Acid Rain Program means a multi-State sulfur dioxide and nitrogen 
oxides air pollution control and emissions reduction program 
established by the Administrator under title IV of the CAA and parts 72 
through 78 of this chapter.
    Acid Rain allowance means a limited authorization issued by the 
Administrator under the Acid Rain Program to emit up to one ton of 
sulfur dioxide during the specified year or any year thereafter.
    Allowance transfer deadline means the allowance transfer deadline 
under the Acid Rain Program, as defined in Sec.  72.2 of this chapter.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating 
water, steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in 
which the energy input to the unit is first used to produce useful 
thermal energy and at least some of the reject heat from the useful 
thermal energy application or process is then used for power 
production.
    CAIR SO₂ Emissions Trading Program means a multi-State 
sulfur dioxide air pollution control and emission reduction program 
established by the Administrator in accordance with subparts AAA 
through HHH of part 96 of this chapter and this section, as a means of 
mitigating interstate transport of fine particulates.
    Cogeneration unit means a unit:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after 
which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input 
or, if useful thermal energy produced is less than 15 percent of total 
energy output, not less than 45 percent of total energy input.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.

[[Page 32737]]

    Combustion turbine means an enclosed device comprising a 
compressor, a combustor, and a turbine and in which the flue gas 
resulting from the combustion of fuel in the combustor passes through 
the turbine, rotating the turbine. A combustion turbine that is 
combined cycle also includes any associated heat recovery steam 
generator and steam turbine.
    Compliance account means a compliance account under the Acid Rain 
Program, as defined in Sec.  72.2 of this chapter.
    Electric generating unit or EGU means:
    (1) Except for a unit under paragraph (2) of this definition, a 
fossil fuel-fired boiler or combustion turbine serving at any time a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale; or
    (2) A fossil fuel-fired cogeneration unit serving at any time a 
generator with nameplate capacity of more than 25 MWe and in any year 
supplying more than one-third of the unit's potential electric output 
capacity or 219,000 MWh, whichever is greater, to any utility power 
distribution system for sale.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, any boiler or 
turbine combusting any amount of fossil fuel.
    Generator means a device that produces electricity.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state 
basis, as specified by the manufacturer of the unit as of the initial 
installation of the unit.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means the maximum electrical generating output 
(in MWe) that a generator can sustain over a specified period of time 
when not restricted by seasonal or other deratings, as specified by the 
manufacturer of the generator as of the initial installation of the 
generator or, if the generator is subsequently modified or 
reconstructed resulting in an increase in such maximum electrical 
generating output, as specified by the person conducting the 
modification or reconstruction.
    Non-EGU means a source of SO₂ emissions that is not an 
EGU.
    SO2 means sulfur dioxide.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from power production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in power production.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power and 
at least some of the reject heat from the power production is then used 
to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is 
not limited to, any on-site processing or treatment of fuel combusted 
at the unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, 
excluding any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a distribution utility and 
dedicated to delivering electricity to customers.
    6. Part 51 is amended by adding Sec.  51.125 to Subpart G to read 
as follows:

Sec.  51.125  Emissions reporting requirements for SIP revisions 
relating to budgets for SO[bdi2]
and NOX emissions.

    (a) For its transport SIP revision under Sec.  51.123 and/or 51.124 
of this part, each State must submit to EPA SO₂ and/or 
NO_X emissions data as described in this section.
    (1) The District of Columbia and following States must report 
annual (12 months) emissions of SO₂ and NO_X: 
Alabama, Arkansas, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, 
Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, 
Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West 
Virginia, and Wisconsin.
    (2) The District of Columbia and the following States must report 
ozone season (May 1 through September 30) emissions of NO_X: 
Alabama, Arkansas, Connecticut, Delaware, Georgia, Illinois, Indiana, 
Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, 
Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and 
Wisconsin.
    (b) Each revision must provide for periodic reporting by the State 
of SO₂ and/or NO_X emissions data as specified in 
paragraph (a) of this section to demonstrate whether the State's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) Every-year reporting cycle. As applicable, each revision must 
provide for reporting of SO₂ and NO_X emissions 
data every year as follows:
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every year from all SO₂ 
and NO_X sources within the State for which the State 
specified control measures in its SIP submission under Sec. Sec.  
51.123 and/or 51.124 of this part.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and summer daily emissions data every year 
from all NO_X sources within the State for which the State 
specified control measures in its SIP submission under Sec.  51.123 of 
this part.
    (iii) If sources report SO₂ and NO_X emissions 
data to EPA in a given year pursuant to a trading program approved 
under Sec.  51.123(o) or Sec.  51.124(o) of this part or pursuant to 
the monitoring and reporting requirements of subpart H of 40 CFR part 
75, then the State need not provide annual reporting of these 
pollutants to EPA for such sources.
    (2) Three-year reporting cycle. As applicable, each plan must 
provide for triennial (i.e., every third year) reporting of 
SO₂ and NO_X emissions data from all sources 
within the State.
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every third year from all 
SO₂ and NO_X sources within the State.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and ozone daily emissions data every third 
year from all NO_X sources within the State.

[[Page 32738]]

    (3) The data availability requirements in Sec.  51.116 of this part 
must be followed for all data submitted to meet the requirements of 
paragraphs (b)(1)and(2) of this section.
    (c) The data reported in paragraph (b) of this section must meet 
the requirements of subpart A of this part.
    (d) Approval of annual and ozone season calculation by EPA. Each 
State must submit for EPA approval an example of the calculation 
procedure used to calculate annual and ozone season emissions along 
with sufficient information for EPA to verify the calculated value of 
annual and ozone season emissions.
    (e) Reporting schedules.
    (1) Reports are to begin with data for emissions occurring in the 
year 2008, which is the first year of the 3-year cycle.
    (2) After 2008, 3-year cycle reports are to be submitted every 
third year and every-year cycle reports are to be submitted each year 
that a triennial report is not required.
    (3) States must submit data for a required year no later than 17 
months after the end of the calendar year for which the data are 
collected.
    (f) Data reporting procedures are given in subpart A. When 
submitting a formal NO_X budget emissions report and 
associated data, States shall notify the appropriate EPA Regional 
Office.
    (g) Definitions. As used in this section, words and terms shall 
have the meanings set forth in appendix A of subpart A of this part.
    7. Sec.  51.308 is amended by revising the introductory text of 
paragraph (e)(2), paragraphs (e)(3) and (e)(4), and by adding paragraph 
(e)(5) as follows:

Sec.  51.308  Regional haze program requirements

* * * * *
    (e) * * *
    (2) A State may opt to implement an emissions trading program or 
other alternative measure rather than to require sources subject to 
BART to install, operate and maintain BART. Except as provided in 
paragraph (e)(3) of this section, to do so, the State must demonstrate 
that this emissions trading program or other alternative measure will 
achieve greater reasonable progress than would be achieved through the 
installation and operation of BART. To make this demonstration, the 
State must submit an implementation plan containing the following plan 
elements and include documentation for all required analyses:
* * * * *
    (3) A State that opts to participate in the Clean Air Interstate 
Rule cap-and-trade program under part 96 AAA-EEE need not require 
affected BART-eligible EGU's to install, operate, and maintain BART. A 
State that chooses this option may also include provisions for a 
geographic enhancement to the program to address the requirement under 
Sec.  51.302(c) related to BART for reasonably attributable impairment 
from the pollutants covered by the CAIR cap-and-trade program.
    (4) After a State has met the requirements for BART or implemented 
emissions trading program or other alternative measure that achieves 
more reasonable progress than the installation and operation of BART, 
BART-eligible sources will be subject to the requirements of Sec.  
51.308(d) in the same manner as other sources.
    (5) Any BART-eligible facility subject to the requirement under 
Sec.  51.308(e) to install, operate, and maintain BART may apply to the 
Administrator for an exemption from that requirement. An application 
for an exemption will be subject to the requirements of Sec.  
51.303(a)(2)-(h).

PART 72--PERMITS REGULATION

    1. The authority citation for part 72 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

Sec.  72.2  [Amended]

    2. Section 72.2 is amended as follows:
    a. Amend the definition of ``Acid rain emissions limitation'' by 
replacing, in paragraph (1)(i), the words ``an affected unit'' by the 
words ``the affected units at a source'' and replacing, in paragraph 
(1)(ii)(C), the words ``compliance subaccount for that unit'' by the 
words ``compliance account for that source'';
    b. Amend the definition of ``Allocate or allocation'' by replacing 
the words ``unit account'' by the words ``compliance account'';
    c. Amend the definition of ``Allowance deduction, or deduct'' by 
replacing the words ``compliance subaccount, or future year 
subaccount,'' by the words ``compliance account'' and replacing the 
words ``from an affected unit'' by the words ``from the affected units 
at an affected source'';
    d. Amend the definition of ``Allowance transfer deadline'' by 
replacing the words ``affected unit's compliance subaccount'' by the 
words ``an affected source's compliance account'' and replacing the 
words ``the unit's'' by the words ``the source's'';
    e. Amend the definition of ``Authorized account representative'' by 
replacing the words ``unit account'' by the words ``compliance 
account'' and replacing the words ``affected unit'' by the words 
``affected source and the affected units at the source'';
    f. Amend the definition of ``Compliance use date'' by replacing the 
word ``unit's'' by the word ``source's'';
    g. Amend the definition of ``excess emissions'' by, in paragraph 
(1), replacing the words ``an affected unit'' by the words ``the 
affected units at an affected source'' and replacing the words ``for 
the unit'' by the words ``for the source'';
    h. Amend the definition of ``Recordation, record, or recorded'' by 
removing the words ``or subaccount''; and
    i. Revise the definition of ``Cogeneration unit'', adding a new 
definition of ``Compliance account'', and removing the definitions of 
``Compliance subaccount'', ``Current year subaccount'', ``Future year 
subaccount'', and ``Unit account'' to read as follows:

Sec.  72.2  Definitions.

* * * * *
    Cogeneration unit means a unit that has equipment used to produce 
electric energy and forms of useful thermal energy (such as heat or 
steam) for industrial, commercial, heating, or cooling purposes, 
through sequential use of energy.
* * * * *
    Compliance account means an Allowance Tracking System account, 
established by the Administrator for an affected source and for each 
affected unit at the source pursuant to Sec.  73.31(a) or (b) of this 
chapter.
* * * * *

Sec.  72.7  [Amended]

    3. Section 72.7 is amended in paragraph (c)(1)(ii), in the first 
sentence, remove the word ``unit's'' and add after the words 
``Allowance Tracking System account'' the words ``of the source that 
includes the unit'' and remove the third sentence.

Sec.  72.9  [Amended]

    4. Section 72.9 is amended by:
    a. In paragraph (c)(1)(i), replace the words ``unit's compliance 
subaccount'' with the words ``source's compliance account'' and replace 
the words ``from the unit'' by the words ``from the affected units at 
the source'';
    b. In paragraphs (e)(1) and (e)(2) introductory text, replace the 
words ``an affected unit'' by the words ``an affected source''; and
    c. In paragraph (g)(6), remove the second sentence.

[[Page 32739]]

Sec.  72.21  [Amended]

    5. Section 72.21 is amended by removing from paragraph (b)(1) the 
word ``affected'' wherever it appears.

Sec.  72.24  [Amended]

    6. Section 72.24 is amended by removing and reserving paragraphs 
(a)(5), (a)(7), and (a)(10).

Sec.  72.40  [Amended]

    7. Section 72.40 is amended, in paragraph (a)(1), replace the words 
``unit's compliance subaccount'' with the words ``compliance account of 
the source where the unit is located '', remove the words ``, or in the 
compliance subaccount of another affected unit at the source to the 
extent provided in Sec.  73.35(b)(3),'', and replace the words ``from 
the unit'' by the words ``from the affected units at the source''.

Sec.  72.73  [Amended]

    8. Section 72.73 is amended, in paragraph (b)(2), replace the words 
``the first Acid Rain permit'' by the words ``an Acid Rain permit''.

Sec.  72.90  [Amended]

    9. Section 72.90 is amended, in paragraph (a), add, after the words 
``each calendar year'', the words ``during 1995 through 2004''.

Sec.  72.95  [Amended]

    10. Section 72.95 is amended by:
    a. In the introductory text, replace the words ``an affected unit's 
compliance subaccount'' with the words ``an affected source's 
compliance account''; and
    b. In paragraph (a), replace the words ``by the unit'' by the words 
``by the affected units at the source''.

PART 73--SULFUR DIOXIDE ALLOWANCE SYSTEM

    1. The authority citation continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

Sec.  73.10  [Amended]

    2. Section 73.10 is amended by:
    a. In paragraph (a), remove the words ``in each future year 
subaccount'';
    b. In paragraph (b)(1), replace the words ``in the future year 
subaccounts representing calendar years'' with the words ``for the 
years''; and
    c. In paragraph (b)(2), replace the words ``in the future year 
subaccounts representing calendar years'' with the words ``for the year''.

Sec.  73.30  [Amended]

    3. Section 73.30 is amended by:
    a. In paragraph (a), replace the words ``affected units'' by the 
words ``affected sources''; and
    b. In paragraph (b), replace the word ``unit'' by the word ``source''.

Sec.  73.31  [Amended]

    4. Section 73.31 is amended by:
    a. In paragraph (a), replace the words ``each unit'' with the words 
``each source that includes a unit'';
    b. In paragraph (b), replace the words ``the unit.'' by the words 
``the source that includes the unit, unless the source already has a 
compliance account.''; and
    c. In paragraph (c)(1)(v), remove the words `` I shall abide by any 
fiduciary responsibilities assigned pursuant to the binding agreement.''.

Sec.  73.32  [Removed and Reserved]

    5. Sec.  73.32 is removed and reserved.

Sec.  73.33  [Amended]

    6. Removing and reserving paragraph (c).

Sec.  73.34  [Amended]

    7. Section 73.34 is amended as follows:
    a. Revise paragraph (a) to read as set forth below;
    b. Remove and reserve paragraph (b); and
    c. In paragraph (c) heading, replace the words ``in subaccounts'' 
with the words ``in compliance accounts'' and in the introductory text, 
replace the words ``compliance, current year, and future year'' with 
the words ``compliance account''.

Sec.  73.34  Recordation in accounts.

    (a) Recordation in compliance accounts. When a compliance account 
is established under Sec.  73.31(a), the Administrator will record in 
the account any allowances allocated to the affected units at the 
source under Sec.  73.10 or part 74 for 30 years starting with the 
later of 1995 or the year in which the account is established. At the 
beginning of 1995 and, in the case of each year thereafter, after the 
Administrator has made all deductions from the compliance account 
pursuant to Sec.  73.35(b), the Administrator will record in the 
compliance account the allowances allocated to such units under Sec.  
73.10 or part 74 for the new 30th year.
* * * * *

Sec.  73.35  [Amended]

    8. Section 73.35 is amended as follows:
    a. In paragraph (a) introductory text and paragraph (a)(1), replace 
the words ``unit's'' by the word ``source's'';
    b. In paragraph (a)(2)(i), replace the words ``the unit's 
compliance subaccount'' with the words ``the compliance account of the 
source that includes the unit'';
    c. In paragraph (a)(2)(ii), replace the words ``the unit's 
compliance subaccount'' with the words ``the compliance account of the 
source that includes the unit'' wherever they appear and remove the 
words ``for the unit'', and replace the words ``; or'' with a period.
    d. Remove paragraph (a)(2)(iii).
    e. In paragraph (b)(1), add after the words ``deduct allowances'' 
the words ``available for deduction under paragraph (a) of this 
section'' and replace the words ``each affected unit's compliance 
subaccount'' with the words ``each affected source's compliance account'';
    f. In paragraph (b)(2), replace the words ``allowances remain in 
the compliance subaccount'' with the words ``allowances available for 
deduction under paragraph (a) of this section remain in the compliance 
account'';
    g. Remove paragraph (b)(3);
    h. Revise paragraph (c)(1) to read as set forth below;
    i. In paragraph (c)(2), replace the words ``for the unit'' with the 
words ``for the units at the source'', replace the words ``in its 
compliance subaccount.'' by the words ``in the source's compliance 
account.'', replace the words ``from the compliance subaccount'' by the 
words ``from the compliance account'', and replace the words ``unit's 
compliance subaccount'' by the words ``source's compliance account'';
    j. In paragraph (d), replace the words ``for each unit'' by the 
words ``for each source'' and replace the word ``unit's'' by the word 
``source's''; and
    k. Remove paragraph (e).

Sec.  73.35  Compliance.

* * * * *
    (c)(1) Identification of allowances by serial number. The 
authorized account representative for a source's compliance account may 
request that specific allowances, identified by serial number, in the 
compliance account be deducted for a calendar year in accordance with 
paragraph (b) or (d) of this section. Such request shall be submitted 
to the Administrator by the allowance transfer deadline for the year 
and include, in a format prescribed by the Administrator, the 
identification of the source and the appropriate serial numbers.
* * * * *

Sec.  73.36  [Amended]

    9. Section 73.36 is amended by:
    a. In paragraph (a), replace the words ``Unit accounts.'' with the 
words ``Compliance accounts.'' and replace with words ``compliance 
subaccount''

[[Page 32740]]

with the words ``compliance account'' whenever they appear; and
    b. In paragraph (b), replace the words ``current year subaccount'' 
with the words ``general account'' whenever they appear.
    10. Section 73.37 is revised to read as follows:

Sec.  73.37  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Tracking System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.

Sec.  73.38  [Amended]

    11. Section 73.38 is amended as follows:
    a. In paragraph (a), replace the words ``delete the general account 
from the Allowance Tracking System.'' by the words ``close the general 
account.''; and
    b. In paragraph (b), remove the words ``and eliminated from the 
Allowance Tracking System'' and the last sentence.

Sec.  73.50  [Amended]

    12. Section 73.50 is amended as follows:
    a. In paragraph (a), remove the words ``, including, but not 
limited to, transfers of an allowance to and from contemporaneous 
future year subaccounts, and transfers of an allowance to and from 
compliance subaccounts and current year subaccounts, and transfers of 
all allowances allocated for a unit for each calendar year in 
perpetuity'';
    b. In paragraph (b)(1)(ii), remove the words ``, or correct 
indication on the allowance transfer where a request involves the 
transfer of the unit's allowance in perpetuity'';
    c. In paragraph (b)(2)(ii), remove the words ``Allowance Tracking 
System'' and ``under 40 CFR part 73, or any other remedies'' and remove 
the comma after the words ``under State or Federal law''; and
    d. Remove paragraph (b)(3).

Sec.  73.51  [Removed and Reserved]

    13. Section 73.51 is removed and reserved.
    14. Section 73.52 is amended as follows revising paragraphs (a)(1), 
(a)(2) and (a)(3) and by removing paragraph (a)(4), and revising 
paragraph (b) and adding a new paragraph (c) to read as follows:

Sec.  73.52  EPA recordation.

    (a) * * *
    (1) The transfer is corrected submitted under Sec.  73.50;
    (2) The transferor account includes each allowance identified by 
serial number in the transfer;
    (3) If the allowances identified by serial number specified 
pursuant to Sec.  73.50(b)(1)(ii) are subject to the limitation on 
transfer imposed pursuant to Sec.  72.44(h)(1)(i) of this chapter, 
Sec.  74.42 of this chapter, or Sec.  74.47(c) of this chapter, the 
transfer is in accordance with such limitation.
    (b) To the extent an allowance transfer submitted for recordation 
after the allowance transfer deadline includes allowances allocated for 
any year before the year of the allowance transfer deadline, the 
transfer of such allowance will not be recorded until after completion 
of the deductions pursuant to Sec.  73.35(b) for year before the year 
of the allowance transfer deadline.
    (c) Where an allowance transfer submitted for recordation fails to 
meet the requirements of paragraph (a) of this section, the 
Administrator will not record such transfer.

Sec.  73.70  [Amended]

    15. Section 73.70 is amended as follows:
    a. In paragraph (f), replace the words ``the subaccount'' by the 
words ``the Allowance Tracking System account''; and
    b. In paragraph (i)(1), add, after the words ``Allowance Tracking 
System account'', the words ``of the source that includes''.

PART 74--SULFUR DIOXIDE OPTS-INS

    1. The authority citation for part 74 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

Sec.  74.18  [Amended]

    2. Section 74.18 is amended, in paragraph (d), remove the last 
sentence.

Sec.  74.40  [Amended]

    3. Section 74.40 is amended, in paragraph (a), add, after the words 
``an account'', the words ``(unless the source that includes the opt-in 
unit already has a compliance account)'' and remove the last sentence.
    4. Section 74.42 is revised to read as follows:

Sec.  74.42  Limitation on transfers.

    (a) With regard to a transfer request submitted for recordation 
during the period starting January 1 and ending with the allowance 
transfer deadline in the same year, the Administrator will not record a 
transfer of an opt-in allowance that is allocated to an opt-in source 
for the year in which the transfer request is submitted or a subsequent 
year.
    (b) With regard to a transfer request during the period starting 
with an allowance transfer deadline and ending December 31 in the same 
year, the Administrator will not record a transfer of an opt-in 
allowance that is allocated to an opt-in source for a year after the 
year in which the transfer request is submitted.

Sec.  74.43  [Amended]

    5. Section 74.43 is amended as follows:
    a. In paragraph (a), remove the words ``in lieu of any annual 
compliance certification report required under subpart I of part 72 of 
this chapter'';
    b. In paragraph (b)(7), replace the word ``At'' by the words, ``In 
an annual compliance certification report for a year during 1995 
through 2004, at''; and
    c. In paragraph (b)(8), replace the word ``The'' by the words, ``In 
an annual compliance certification report for a year during 1995 
through 2004, the''.

Sec.  74.44  [Amended]

    6. Section 74.44 is amended as follows:
    a. In paragraphs (c)(2)(iii)(C), (c)(2)(iii)(D), (c)(2)(iii)(E) 
introductory text, and (c)(2)(iii)(E)(3), replace the words ``opt-in 
source's compliance subaccount'' by the words ``compliance account of 
the source that includes the opt-in source'' whenever they occur; and
    b. In paragraph (c)(2)(iii)(F), replace the words ``opt-in source's 
compliance subaccount'' by the words ``compliance account of the source 
that includes the opt-in source'' and replace the words ``source's 
compliance subaccount'' by the words ``compliance account of the source 
that includes the opt-in source''.

Sec.  74.46  [Amended]

    7. Section 74.6 is amended by removing and reserving paragraph (b)(2).

Sec.  74.47  [Amended]

    8. Section 74.47 is amended as follows:
    a. In paragraph (c), replace the words ``unit account'' by the 
words ``compliance account of the source that includes the replacement 
unit''; and
    b. In paragraph (d)(2), add, after the words ``Allowance Tracking 
System accounts'', the words ``of the source that include the opt-in 
source and each replacement unit'' and remove the words ``for the opt-
in source and for each replacement unit''.

Sec.  74.49  [Amended]

    9. Section 74.49 is amended, in paragraph (a), replace the words 
``an opt-in source's compliance subaccount''

[[Page 32741]]

by the words ``the compliance account of a source that include an opt-
in source''.

Sec.  74.50  [Amended]

    10. Section 74.50 is amended as follows:
    a. In paragraph (a)(2) introductory text, add, after the words 
``the account of the'' the words ``source that includes'';
    b. In paragraph (a)(2)(i), replace the words ``opt-in source's 
compliance subaccount'' by the words ``the compliance account of the 
source that includes the opt-in source''; and
    c. In paragraph (b), replace the words ``the opt-in source's unit 
account'' by the words ``the compliance account of the source that 
includes the opt-in source''; and
    d. In paragraph (d), replace the words ``an opt-in source does not 
hold'' by the words ``the source that include the opt-in source does 
not hold''.

PART 77--EXCESS EMISSIONS

    1. The authority citation for part 77 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

Sec.  77.3  [Amended]

    2. Section 77.3 is amended as follows:
    a. In paragraph (a), replace the words ``affected unit'' by the 
words ``affected source'' and replace the word ``unit's'' by the word 
``source's'';
    b. In paragraphs (b) and (c), replace the word ``unit'' by the word 
``source'' wherever it appears; and
    c. In paragraph (d) introductory text and paragraphs (d)(1), 
(d)(2), (d)(3), and (d)(5), replace the word ``unit'' by the word 
``source'' wherever it appears, replace the word ``unit's'' by the word 
``source's'' wherever it appears, and replace the words ``compliance 
subaccount'' by the words ``compliance account''.

Sec.  77.4  [Amended]

    3. Section 77.4 is amended, in paragraphs (c)(1)(ii)(A), (d)(1), 
(d)(2), (d)(3), (g)(2)(ii), (g)(3)(ii), and (g)(3)(iii), by replacing 
the word ``unit'' by the word ``source''.

Sec.  77.5  [Amended]

    4. Section 77.5 is amended by:
    a. In paragraph (b), replace the words ``compliance subaccount'' 
with the words ``compliance account'';
    b. In paragraph (c), replace the words ``, from the unit's 
compliance subaccount'' with the words ``allocated for the year after 
the year in which the source has excess emissions, from the source's 
compliance account'' and replace the word ``unit's'' by the word 
``source's''; and
    c. Remove paragraph (d).

Sec.  77.6  [Amended]

    5. Section 77.6 is amended by, in paragraph (a)(1), add, after the 
words ``sulfur dioxide'', the words occur at the affected source'' and 
add, after the words ``owners and operators of'', the words ``the 
affected source or''.

PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM

    1. The authority citation for part 78 continues to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et seq.

Sec.  78.1  [Amended]

    2. Section 78.1 is amended, in paragraph (a)(1), replace the words 
``parts 72, 73, 74, 75, 76, or 77 of this chapter or part 97 of this 
chapter'' by the words ``part 72, 73, 74, 75, 76, or 77 of this 
chapter, subparts AA through GG and subparts AAA and GGG of part 96 of 
this chapter, or part 97 of this chapter'' and add new paragraphs 
(b)(7) and (b)(8) to read as follows:

Sec.  78.1  Purpose and scope.

    (b) * * *
    (7) Under subparts AA through GG of part 96 of this chapter,
    (i) The decision on the deduction of CAIR NO_X 
allowances, and the adjustment of the information in a submission and 
the deduction or transfer of CAIR NO_X allowances based on 
the information, as adjusted, under Sec.  96.154;
    (ii) The correction of an error in a CAIR NO_X Allowance 
Tracking System account under Sec.  97.156;
    (iii) The decision on the transfer of CAIR NO_X 
allowances under Sec.  96.161;
    (iv) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (v) The approval or disapproval of a petition under Sec.  96.175.
    (8) Under subparts AAA through GGG of part 96 of this chapter,
    (i) The decision on the deduction of CAIR SO₂ 
allowances, and the adjustment of the information in a submission and 
the deduction or transfer of CAIR SO₂ allowances based on 
the information, as adjusted, under Sec.  96.254;
    (ii) The correction of an error in a CAIR SO₂ Allowance 
Tracking System account under Sec.  97.256;
    (iii) The decision on the transfer of CAIR SO₂ 
allowances under Sec.  96.261;
    (iv) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (v) The approval or disapproval of a petition under Sec.  96.275.

Sec.  78.3  [Amended]

    3. Section 78.3 is amended by:
    a. Amend paragraph (b)(3)(i) by adding, after the words ``(unless 
the NO_X authorized account representative is the 
petitioner)'', the words ``or the CAIR designated representative or 
CAIR authorized account representative under paragraph (a)(5) or (a)(6) 
of this section (unless the CAIR designated representative or CAIR 
authorized account representative is the petitioner)'';
    b. In paragraph (c)(7) replace the words ``or part 97 of this 
chapter, as appropriate'' by the words ``, subparts AA through GG of 
part 96 of this chapter, subparts AAA through GGG of part 96 of this 
chapter, or part 97 of this chapter, as appropriate'';
    c. In paragraph (d)(2) add, after the words ``under the 
NO_X Budget Trading Program'', the words ``or on an account 
certificate of representation submitted by a CAIR designated 
representative or an application for a general account submitted by a 
CAIR authorized account representative under subparts AA through GG of 
part 96 of this chapter or subparts AAA through GGG of part 96 of this 
chapter,'';
    d. Add new paragraphs (a)(5), (a)(6), and (d)(5) and (d)(6).
    The additions and revisions read as follows:

Sec.  78.3  Petition for administrative review and request for 
evidentiary hearing.

    (a) * * *
    (5) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AA through 
GG of part 96 and that is appealable under Sec.  78.1(a) of this part:
    (i) The CAIR designated representative for a source or the CAIR 
authorized account representative for any CAIR NO_X Allowance 
Tracking System account covered by the decision; or
    (ii) Any interested person.
    (6) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAA through 
GGG of part 96 and that is appealable under Sec.  78.1(a) of this part:
    (i) The CAIR designated representative for a source or the CAIR 
authorized account representative for any CAIR SO₂ Allowance 
Tracking System account covered by the decision; or
    (ii) Any interested person.
* * * * *

[[Page 32742]]

    (d) * * *
    (5) Any provision or requirement of subparts AA through GG of part 
96, including the standard requirements under Sec.  96.106 of this 
chapter and any emission monitoring or reporting requirements.
    (6) Any provision or requirement of subparts AAA through GGG of 
part 96, including the standard requirements under Sec.  96.206 of this 
chapter and any emission monitoring or reporting requirements.
* * * * *

Sec.  78.4  [Amended]

    4. Section 78.4 is amended by adding two new sentences after the 
fifth sentence in paragraph (a) to read as follows:

Sec.  78.4  Filings.

    (a) * * * Any filings on behalf of owners and operators of a CAIR 
unit or source shall be signed by the CAIR designated representative. 
Any filings on behalf of persons with an interest in CAIR 
NO_X or SO₂ allowances in a general account shall 
be signed by the CAIR authorized account representative. * * *
* * * * *

Sec.  78.12  [Amended]

    5. Section 78.12 is amended, in paragraph (a)(2), by adding, after 
the words ``a NO_X Budget permit'', the words '', CAIR 
permit,''.

PART 96--[AMENDED]

    1. Authority citation for Part 96 continues to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7601.
    2. Part 96 is amended by adding subparts AA through CC, adding and 
reserving subpart DD and adding subparts EE through HH to read as follows:

Subpart AA--CAIR NOX Trading Program General Provisions

Sec.
96.101 Purpose.
96.102 Definitions.
96.103 Measurements, abbreviations, and acronyms.
96.104 Applicability.
96.105 Retired unit exemption.
96.106 Standard requirements.
96.107 Computation of time.
96.108 Appeal Procedures.
Subpart BB--CAIR Designated Representative for CAIR Sources
96.110 Authorization and responsibilities of CAIR designated 
representative.
96.111 Alternate CAIR designated representative.
96.112 Changing CAIR designated representative and alternate CAIR 
designated representative; changes in owners and operators.
96.113 Certificate of representation.
96.114 Objections concerning CAIR designated representative.
Subpart CC--Permits
96.120 General CAIR NO_X Trading Program permit requirements.
96.121 Submission of CAIR permit applications.
96.122 Information requirements for CAIR permit applications.
96.123 CAIR permit contents and term.
96.124 CAIR permit revisions.
Subpart DD--[Reserved]
Subpart EE--CAIR NOX Allowance Allocations
96.140 State trading budgets.
96.141 Timing requirements for CAIR NO_X allowance allocations.
96.142 CAIR NO_X allowance allocations.
Subpart FF--CAIR NOX Allowance Tracking System
96.150 CAIR NOX Allowance Tracking System accounts.
96.151 Establishment of accounts.
96.152 Responsibilities of CAIR NO_X authorized account 
representative.
96.153 Recordation of CAIR NO_X allowance allocations.
96.154 Compliance with CAIR NO_X emissions limitation.
96.155 Banking.
96.156 Account error.
96.157 Closing of general accounts.
Subpart GG--CAIR NOX Allowance Transfers
96.160 Submission of CAIR NO_X allowance transfers.
96.161 EPA recordation.
96.162 Notification.
Subpart HH--Monitoring and Reporting
96.170 General requirements.
96.171 Initial certification and recertification procedures.
96.172 Out of control periods.
96.173 Notifications.
96.174 Recordkeeping and reporting.
96.175 Petitions.
96.176 Additional requirements to provide heat input data.

Subpart AA--CAIR NOX Trading Program General Provisions

Sec.  96.101  Purpose.

    This subpart establishes the model rule comprising general 
provisions and the applicability, permitting, allowance, excess 
emissions, and monitoring for the state Clean Air Interstate Rule 
(CAIR) NO_X Trading Program, under section 110 of the Clean 
Air Act (CAA) and Sec.  51.123 of this chapter, as a means of reducing 
national NO_X emissions.

Sec.  96.102  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR NO_X Allowance Tracking System 
account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NO_X 
allowances, the determination by the Administrator of the amount of 
CAIR NO_X allowances to be initially credited to a CAIR unit 
or a new unit set-aside.
    Alternate CAIR designated representative means, for a CAIR source 
and each CAIR unit at the source, the natural person who is authorized 
by the owners and operators of the source and all CAIR units at the 
source in accordance with subpart BB of this part, to act on behalf of 
the CAIR designated representative in matters pertaining to the CAIR 
SO₂ Trading Program and the CAIR NO_X Trading 
Program. This natural person shall be the same person as the alternate 
designated representative under the Acid Rain Program under Sec.  72.22 
of this chapter.
    Automated data acquisition and handling system or DAHS means that 
component of the CEMS, or other emissions monitoring system approved 
for use under subpart HH of this part, designed to interpret and 
convert individual output signals from pollutant concentration 
monitors, flow monitors, diluent gas monitors, and other component 
parts of the monitoring system to produce a continuous record of the 
measured parameters in the measurement units required by subpart HH of 
this part.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating 
water, steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in 
which the energy input to the unit is first used to produce useful 
thermal energy and at least some of the reject heat from the useful 
thermal energy application or

[[Page 32743]]

process is then used for power production.
    CAIR designated representative means, for a CAIR source and each 
CAIR unit at the source, the natural person who is authorized by the 
owners and operators of the source and all CAIR units at the source, in 
accordance with subpart BB of this part, to represent and legally bind 
each owner and operator in matters pertaining to the CAIR 
SO₂ Trading Program and to the CAIR NO_X Trading 
Program. This natural person shall be the same person who is the 
authorized account representative under the Acid Rain Program under 
Sec.  72.20 of this chapter.
    CAIR NO_X allowance means a limited authorization issued 
by the Administrator to emit up to one ton of nitrogen oxide during the 
control period of the specified year or of any year thereafter under 
the CAIR NO_X Program or, except for purposes of subpart EE 
of this part, any NO_X SIP Call allowance, allocated for the 
2009, or any earlier, ozone season that is not used to meet an 
NO_X emissions limitation under the NO_X Budget 
Trading Program.
    CAIR NO_X allowance deduction or deduct CAIR 
NO_X allowances means the permanent withdrawal of CAIR 
NO_X allowances by the Administrator from a compliance 
account in order to account for a specified number of tons of nitrogen 
oxide emissions from all CAIR units at a CAIR source for a control 
period, determined in accordance with subparts FF and HH of this part, 
or to account for excess emissions.
    CAIR NO_X Allowance Tracking System (INATS) means the 
system by which the Administrator records allocations, deductions, and 
transfers of CAIR NO_X allowances under the CAIR 
NO_X Trading Program.
    CAIR NO_X Allowance Tracking System account means an 
account in the CAIR NO_X Allowance Tracking System 
established by the Administrator for purposes of recording the 
allocation, holding, transferring, or deducting of CAIR NO_X 
allowances.
    CAIR NO_X allowance transfer deadline means midnight of 
March 1 or, if March 1 is not a business day, midnight of the first 
business day thereafter and is the deadline by which a CAIR 
NO_X allowance transfer must be submitted for recordation in 
a CAIR source's compliance account in order to meet the source's CAIR 
NO_X emissions limitation for the control period immediately 
preceding such deadline.
    CAIR NO_X allowances held or hold CAIR NO_X 
allowances means the CAIR NO_X allowances recorded by the 
Administrator, or submitted to the Administrator for recordation, in 
accordance with subparts FF and GG of this part, in a CAIR 
NO_X Allowance Tracking System account.
    CAIR NO_X authorized account representative means a 
responsible natural person who is authorized, in accordance with 
subpart BB of this part, to transfer and otherwise dispose of CAIR 
NO_X allowances held in a CAIR NO_X Allowance 
Tracking System general account; or, in the case of a compliance 
account, the CAIR designated representative of the source.
    CAIR NO_X emissions limitation means, for a CAIR source, 
the tonnage equivalent of the CAIR NO_X allowances available 
for compliance deduction for the source under Sec. Sec.  96.154(a) and 
(b) in a control period.
    CAIR NO_X Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator in accordance with subparts AA through HH of this 
part and Sec.  51.123 of this chapter, as a means of mitigating 
interstate transport of fine particulates, ozone, and nitrogen oxides.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CC of this part, including any permit 
revisions, specifying the CAIR SO₂ and NO_X 
Trading Program requirements applicable to a CAIR source, to each CAIR 
unit at the CAIR source, and to the owners and operators and the CAIR 
designated representative of the CAIR source and each CAIR unit.
    CAIR SO₂ Trading Program means a multi-state sulfur 
dioxide air pollution control and emission reduction program 
established by the Administrator in accordance with subparts AAA 
through HHH of this part and Sec.  51.124 of this chapter, as a means 
of mitigating interstate transport of fine particulates.
    CAIR source means a source that includes one or more CAIR units.
    CAIR unit means a unit that is subject to the CAIR NO_X 
Trading Program under Sec.  96.104.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means, with regard to a unit, combusting coal or any 
coal-derived fuel alone or in combination with any amount of any other 
fuel in any year.
    Cogeneration unit means a unit:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after 
which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input 
or, if useful thermal energy produced is less than 15 percent of total 
energy output, not less than 45 percent of total energy input.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.
    Combustion turbine means an enclosed device comprising a 
compressor, a combustor, and a turbine and in which the flue gas 
resulting from the combustion of fuel in the combustor passes through 
the turbine, rotating the turbine. A combustion turbine that is 
combined cycle also includes any associated heat recovery steam 
generator and steam turbine.
    Commence commercial operation means, with regard to a unit that 
serves a generator, to have begun to produce steam, gas, or other 
heated medium used to generate electricity for sale or use, including 
test generation. Except as provided in Sec.  96.105, for a unit that is 
a CAIR unit under Sec.  96.104 on the date the unit commences 
commercial operation, such date shall remain the unit's date of 
commencement of commercial operation even if the unit is subsequently 
modified or reconstructed. Except as provided in Sec.  96.105, for a 
unit that is not a CAIR unit under Sec.  96.104 on the date the unit 
commences commercial operation, the date the unit becomes a CAIR unit 
under Sec.  96.104 shall be the unit's date of commencement of 
commercial operation.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber. Except as provided in Sec.  96.105, for a 
unit that is a CAIR unit under Sec.  96.104 on the date of commencement 
of operation, such date shall remain the unit's date of commencement of 
operation even if the unit is subsequently modified or reconstructed. 
Except as provided in Sec.  96.105, for a unit that is not a CAIR

[[Page 32744]]

unit under Sec.  96.104 on the date of commencement of operation, the 
date the unit becomes a CAIR unit under Sec.  96.104 shall be the 
unit's date of commencement of operation.
    Common stack means a single flue through which emissions from two 
or more units are exhausted.
    Compliance account means a CAIR NO_X Allowance Tracking 
System account, established by the Administrator for a CAIR source 
under subpart FF of this part, in which the CAIR NO_X 
allowance allocations for the CAIR units at the source are initially 
recorded and in which are held CAIR NO_X allowances available 
for use for a control period in order to meet the source's CAIR 
NO_X emissions limitation.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HH of this part to sample, analyze, measure, and 
provide, by means of readings recorded at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of nitrogen oxide (NO_X) emissions, stack 
gas volumetric flow rate or stack gas moisture content (as applicable), 
in a manner consistent with part 75 of this chapter. The following 
systems are the principal types of continuous emission monitoring 
systems required under subpart HH of this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in 
standard cubic feet per hour (scfh);
    (2) A nitrogen oxides (NO_X) concentration monitoring 
system, consisting of a NO_X pollutant concentration monitor 
and an automated DAHS. A NO_X concentration monitoring system 
provides a permanent, continuous record of NO_X emissions, in 
parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NO_X-diluent) 
monitoring system, consisting of a NO_X pollutant 
concentration monitor, a diluent gas (CO₂ or O₂) 
monitor, and an automated DAHS. A NO_X-diluent monitoring 
system provides a permanent, continuous record of: NO_X 
concentration, in parts per million (ppm); diluent gas concentration, 
in percent CO₂ or O₂ (percent CO₂ or 
O₂); and NO_X emission rate, in pounds per million 
British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec.  75.11(b)(2) 
of this chapter. A moisture monitoring system provides a permanent, 
continuous record of the stack gas moisture content, in percent 
H₂O (percent H₂O);
    (5) A carbon dioxide (CO₂) monitoring system, consisting 
of a CO₂ pollutant concentration monitor (or an oxygen 
monitor plus suitable mathematical equations from which the 
CO₂ concentration is derived) and the automated DAHS. A 
carbon dioxide monitoring system provides a permanent, continuous 
record of CO₂ emissions, in percent CO₂ (percent 
CO₂); and
    (6) An oxygen (O₂) monitoring system, consisting of an 
O₂ concentration monitor and an automated DAHS. An 
O₂ monitoring system provides a permanent, continuous record 
of O₂ in percent O₂ (percent O₂).
    Control period means the period beginning January 1 of a year and 
ending on December 31 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the 
Administrator by the CAIR designated representative and as determined 
by the Administrator in accordance with subpart HH of this part.
    Energy Information Administration means the Energy Information 
Administration of the United States Department of Energy.
    Excess emissions means any ton of nitrogen oxide emitted by the 
CAIR units at a CAIR source during a control period that exceeds the 
CAIR NO_X emissions limitation for the source.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, any boiler or 
turbine combusting any amount of fossil fuel.
    General account means a CAIR NO_X Allowance Tracking 
System account, established under subpart FF of this part, that is not 
a compliance account.
    Generator means a device that produces electricity.
    Gross thermal energy means, with regard to a cogeneration unit, 
useful thermal energy output plus, where such output is made available 
for an industrial or commercial process, any heat contained in 
condensate return or makeup water.
    Heat input means, with regard to a specified period to time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and as determined by the Administrator in accordance 
with subpart HH of this part. Heat input does not include the heat 
derived from preheated combustion air, recirculated flue gases, or 
exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided 
by unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a customer reserves, or 
is entitled to receive, a specified amount or percentage of nameplate 
capacity and associated energy from any specified unit and pays its 
proportional amount of such unit's total costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the 
economic useful life of the unit determined as of the time the unit is 
built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state 
basis, as specified by the manufacturer of the unit as of the initial 
installation of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HH of this part, including a continuous 
emissions monitoring system or an alternative monitoring system.
    Nameplate capacity means the maximum electrical generating output 
(in MWe) that a generator can sustain over a specified period of time 
when not restricted by seasonal or other deratings as specified by the 
manufacturer of the generator as of the initial installation of the 
generator or, if the generator is subsequently modified or 
reconstructed resulting in an increase in such maximum electrical 
generating output, as specified by the person conducting the 
modification or reconstruction.
    NO_X Budget Trading Program means a multi-state nitrogen 
oxide air pollution control and emission reduction program established 
by air pollution control and emission

[[Page 32745]]

reduction program established by the Administrator in accordance with 
subparts A through I of this part and Sec.  51.121 of this chapter, as 
a means of mitigating interstate transport of ozone and nitrogen 
oxides.
    NO_X SIP Call allowance means a limited authorization 
issued by the Administrator under the NO_X Budget Trading 
Program to emit up to one ton of nitrogen oxides during the ozone 
season of the specified year or any year thereafter under the 
NO_X Budget Trading Program or during the control period in 
2010 or any year thereafter under the CAIR NO_X Trading 
Program, provided that Sec.  96.54(f) of this chapter shall not apply 
to the use of such allowance under Sec.  96.154.
    Operator means any person who operates, controls, or supervises a 
CAIR unit or a CAIR source and shall include, but not be limited to, 
any holding company, utility system, or plant manager of such a unit or 
source.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
CAIR unit; or
    (2) Any holder of a leasehold interest in a CAIR unit; or
    (3) Any purchaser of power from a CAIR unit under a life-of-the-
unit, firm power contractual arrangement; provided that, unless 
expressly provided for in a leasehold agreement, owner shall not 
include a passive lessor, or a person who has an equitable interest 
through such lessor, whose rental payments are not based (either 
directly or indirectly) on the revenues or income from the CAIR unit; 
or
    (4) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR NO_X allowances 
held in the general account and who is subject to the binding agreement 
for the CAIR authorized account representative to represent that 
person's ownership interest with respect to CAIR NO_X 
allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of 
the CAIR NO_X Trading Program in accordance with subpart CC 
of this part.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 mmBtu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official 
correspondence log, or by a notation made on the document, information, 
or correspondence, by the permitting authority or the Administrator in 
the regular course of business.
    Recordation, record, or recorded means, with regard to CAIR 
NO_X allowances, the movement of CAIR NO_X 
allowances by the Administrator into or between CAIR NO_X 
Allowance Tracking System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec.  75.22 of this 
chapter.
    Serial number means for a CAIR NO_X allowance, the unique 
identification number assigned to each CAIR NO_X allowance by 
the Administrator, under Sec.  96.153(f).
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from power production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in power production.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, 
shall be considered a single ``facility.''
    State means one of the 50 States or the District of Columbia that 
adopts the CAIR NO_X Trading Program pursuant to Sec.  51.123 
of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission,'' ``service,'' or ``mailing'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR NO_X emissions limitation, total tons of 
nitrogen oxides emissions for a control period shall be calculated as 
the sum of all recorded hourly emissions (or the mass equivalent of the 
recorded hourly emission rates) in accordance with subpart HH of this 
part, with any remaining fraction of a ton equal to or greater than 
0.50 tons deemed to equal one ton and any remaining fraction of a ton 
less than 0.50 tons deemed to equal zero tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power and 
at least some of the reject heat from the power production is then used 
to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary boiler or combustion turbine.
    Unit operating day means a calendar day in which a unit combusts 
any fuel.
    Unit operating hour or hour of unit operation means an hour in 
which a unit combusts any fuel. Useful power means, with regard to a 
cogeneration unit, electricity or mechanical energy made available for 
use, excluding any such energy used in the power production process 
(which process includes, but is not limited to, any on-site processing 
or treatment of fuel combusted at the unit and any on-site emission 
controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, 
excluding any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a distribution utility and 
dedicated to delivering electricity to customers.

[[Page 32746]]

Sec.  96.103  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this part are 
defined as follows:

Btu--British thermal unit.
CO₂--carbon dioxide.
NO_X--nitrogen oxide.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
mmBtu--million Btu.
MWe--megawatt electrical.
MWh--megawatt hour.
O₂--oxygen.
SO₂--sulfur dioxide.
yr--year.

Sec.  96.104  Applicability.

    The following units in a State shall be CAIR units, and any source 
that includes one or more such units shall be a CAIR source, subject to 
the requirements of this subpart and subparts BB through HH of this 
part:
    (a) Except a unit under paragraph (b) of this section, a fossil 
fuel-fired boiler or combustion turbine serving at any time a generator 
with nameplate capacity of more than 25 MWe producing electricity for 
sale.
    (b) A fossil fuel-fired cogeneration unit serving at any time a 
generator with nameplate capacity of more than 25 MWe and in any year 
supplying more than one-third of the unit's potential electric output 
capacity or 219,000 MWh, whichever is greater, to any utility power 
distribution system for sale.

Sec.  96.105  Retired unit exemption.

    (a) This section applies to any CAIR unit that is permanently retired.
    (b)(1) Any CAIR unit that is permanently retired shall be exempt 
from the CAIR NO_X Trading Program, except for the provisions 
of this section, Sec.  96.102, Sec.  96.103, Sec.  96.104, Sec.  
96.106(c)(5) through (8), Sec.  96.107, and subparts EE through GG of 
this part.
    (2) The exemption under paragraph (b)(1) of this section shall 
become effective the day on which the unit is permanently retired. 
Within 30 days of permanent retirement, the CAIR designated 
representative shall submit a statement to the permitting authority 
otherwise responsible for administering any CAIR permit for the unit. 
The CAIR designated representative shall submit a copy of the statement 
to the Administrator. The statement shall state, in a format prescribed 
by the permitting authority, that the unit was permanently retired on a 
specific date, and will comply with the requirements of paragraph (c) 
of this section.
    (3) After receipt of the notice under paragraph (b)(2) of this 
section, the permitting authority will amend any permit under subpart 
CC of this part covering the source at which the unit is located to add 
the provisions and requirements of the exemption under paragraphs 
(b)(1) and (c) of this section.
    (c) Special provisions.
    (1) A unit exempt under this section shall not emit any nitrogen 
oxides, starting on the date that the exemption takes effect.
    (2) The permitting authority will allocate CAIR NO_X 
allowances under subpart EE of this part to a unit exempt under this 
section.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under this section shall 
retain at the source that includes the unit, records demonstrating that 
the unit is permanently retired. The 5-year period for keeping records 
may be extended for cause, at any time prior to the end of the period, 
in writing by the permitting authority or the Administrator. The owners 
and operators bear the burden of proof that the unit is permanently 
retired.
    (4) The owners and operators and, to the extent applicable, the 
CAIR designated representative of a unit exempt under this section 
shall comply with the requirements of the CAIR NO_X Trading 
Program concerning all periods for which the exemption is not in 
effect, even if such requirements arise, or must be complied with, 
after the exemption takes effect.
    (5) A unit exempt under this section and located at a source that 
is required, or but for this exemption would be required, to have a 
title V operating permit shall not resume operation unless the CAIR 
designated representative of the source submits a complete CAIR permit 
application under Sec.  96.122 for the unit not less than 18 months (or 
such lesser time provided by the permitting authority) before the later 
of January 1, 2010 or the date on which the unit resumes operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (b) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (c)(5) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (c)(5) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (7) For the purpose of applying monitoring requirements under 
subpart HH of this part, a unit that loses its exemption under this 
section shall be treated as a unit that commences operation and 
commercial operation on the first date on which the unit resumes 
operation.

Sec.  96.106  Standard requirements.

    (a) Permit Requirements.
    (1) The CAIR designated representative of each CAIR source required 
to have a title V operating permit and each CAIR unit required to have 
a title V operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec.  96.122 in accordance with the deadlines 
specified in Sec.  96.121(b) and (c); and
    (ii) Submit in a timely manner any supplemental information that 
the permitting authority determines is necessary in order to review a 
CAIR permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR source required to have a 
title V operating permit and each CAIR unit required to have a title V 
operating permit at the source shall have a CAIR permit issued by the 
permitting authority and operate the unit in compliance with such CAIR 
permit.
    (3) The owners and operators of a CAIR source that is not otherwise 
required to have a title V operating permit are not required to submit 
a CAIR permit application, and to have a CAIR permit, under subpart CC 
of this part for such CAIR source.
    (b) Monitoring requirements.
    (1) The owners and operators and, to the extent applicable, the 
CAIR designated representative of each CAIR source and each CAIR unit 
at the source shall comply with the monitoring requirements of subpart 
HH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HH of this part shall be used to determine compliance by 
the unit with the CAIR NO_X emissions limitation under 
paragraph (c) of this section.
    (c) Nitrogen oxide emission requirements.
    (1) As of the CAIR NO_X allowance transfer deadline for a 
control period, the owners and operators of each CAIR source and each 
CAIR unit at the source shall hold, in the source's compliance account, 
CAIR NO_X allowances available for compliance deductions for 
the control period under Sec.  96.154(a) in an amount not less than the 
total nitrogen oxides emissions for the

[[Page 32747]]

control period from all CAIR units at the source, as determined in 
accordance with subpart HH of this part.
    (2) Each ton of nitrogen oxide emitted in excess of the CAIR 
NO_X emissions limitation shall constitute a separate 
violation of this subpart, the Clean Air Act, and applicable State law.
    (3) A CAIR unit shall be subject to the requirements under 
paragraph (c)(1) of this section starting on the later of January 1, 
2010 or the deadline for meeting the unit's monitor certification 
requirements under Sec.  96.170(b)(1) or (b)(2).
    (4) A CAIR NO_X allowance shall not be deducted, in order 
to comply with the requirements under paragraph (c)(1) of this section, 
for a control period in a year prior to the year for which the CAIR 
NO_X allowance was allocated.
    (5) CAIR NO_X allowances shall be held in, deducted from, 
or transferred into or among CAIR NO_X Allowance Tracking 
System accounts in accordance with subpart EE of this part.
    (6) A CAIR NO_X allowance is a limited authorization to 
emit one ton of nitrogen oxide in accordance with the CAIR 
NO_X Trading Program. No provision of the CAIR NO_X 
Trading Program, the CAIR permit application, the CAIR permit, or 
exemption under Sec.  96.105 and no provision of law shall be construed 
to limit the authority of the State or the United States to terminate 
or limit such authorization.
    (7) A CAIR NO_X allowance does not constitute a property 
right.
    (8) Upon recordation by the Administrator under subparts FF and GG 
of this part, every allocation, transfer, or deduction of a CAIR 
NO_X allowance to or from a CAIR unit's compliance account is 
incorporated automatically in any CAIR permit of the CAIR unit.
    (d) Excess emissions requirements.
    (1) The owners and operators of a CAIR unit that has excess 
emissions in any control period shall:
    (i) Surrender the CAIR NO_X allowances required for 
deduction under Sec.  96.154(d)(1); and
    (ii) Pay any fine, penalty, or assessment or comply with any other 
remedy imposed under Sec.  96.154(d)(2).
    (e) Recordkeeping and Reporting Requirements.
    (1) Unless otherwise provided, the owners and operators of the CAIR 
source and each CAIR unit at the source shall keep on site at the 
source each of the following documents for a period of 5 years from the 
date the document is created. This period may be extended for cause, at 
any time prior to the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The certificate of representation under Sec.  96.113 for the 
CAIR designated representative for the source and each CAIR unit at the 
source and all documents that demonstrate the truth of the statements 
in the certificate of representation; provided that the certificate and 
documents shall be retained on site at the source beyond such 5-year 
period until such documents are superseded because of the submission of 
a new certificate of representation under Sec.  96.113 changing the 
CAIR designated representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HH of this part; provided that to the extent that subpart HH of 
this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
NO_X Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR NO_X 
Trading Program or to demonstrate compliance with the requirements of 
the CAIR NO_X Trading Program.
    (2) The CAIR designated representative of a CAIR source and each 
CAIR unit at the source shall submit the reports required under the 
CAIR NO_X Trading Program, including those under subpart HH 
of this part.
    (f) Liability.
    (1) Any person who knowingly violates any requirement or 
prohibition of the CAIR NO_X Trading Program, a CAIR permit, 
or an exemption under Sec.  96.105 shall be subject to enforcement 
pursuant to applicable State or Federal law.
    (2) Any person who knowingly makes a false material statement in 
any record, submission, or report under the CAIR NO_X Trading 
Program shall be subject to criminal enforcement pursuant to the 
applicable State or Federal law.
    (3) No permit revision shall excuse any violation of the 
requirements of the CAIR NO_X Trading Program that occurs 
prior to the date that the revision takes effect.
    (4) Each CAIR source and each CAIR unit shall meet the requirements 
of the CAIR NO_X Trading Program.
    (5) Any provision of the CAIR NO_X Trading Program that 
applies to a CAIR source or the CAIR designated representative of a 
CAIR source shall also apply to the owners and operators of such source 
and of the CAIR units at the source.
    (6) Any provision of the CAIR NO_X Trading Program that 
applies to a CAIR unit or the CAIR designated representative of a CAIR 
unit shall also apply to the owners and operators of such unit.
    (g) Effect on Other Authorities. No provision of the CAIR 
NO_X Trading Program, a CAIR permit application, a CAIR 
permit, or an exemption under Sec.  96.105 shall be construed as 
exempting or excluding the owners and operators and, to the extent 
applicable, the CAIR designated representative of a CAIR source or CAIR 
unit from compliance with any other provision of the applicable, 
approved State implementation plan, a federally enforceable permit, or 
the Clean Air Act.

Sec.  96.107  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR NO_X Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR NO_X Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day 
before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR NO_X Trading Program, falls on a weekend or a 
State or Federal holiday, the time period shall be extended to the next 
business day.

Sec.  96.108  Appeal Procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR NO_X Trading Program are set forth in part 78 of this 
chapter.

Subpart BB--CAIR Designated Representative for CAIR Sources

Sec.  96.110  Authorization and responsibilities of CAIR designated 
representative.

    (a) Except as provided under Sec.  96.111, each CAIR source, 
including all CAIR units at the source, shall have one and only one 
CAIR designated representative, with regard to all matters under the 
CAIR NO_X Trading Program concerning the source or any CAIR 
unit at the source.
    (b) The CAIR designated representative of the CAIR source shall be 
selected by an agreement binding on the owners and operators of the 
source and all CAIR units at the source and shall act in accordance 
with the certification statement in Sec.  96.113(a)(5)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  96.113, the CAIR designated representative 
of the source shall represent and, by his or her representations, 
actions, inactions, or submissions, legally bind each owner

[[Page 32748]]

and operator of the CAIR source represented and each CAIR unit at the 
source in all matters pertaining to the CAIR NO_X Trading 
Program, notwithstanding any agreement between the CAIR designated 
representative and such owners and operators. The owners and operators 
shall be bound by any decision or order issued to the CAIR designated 
representative by the permitting authority, the Administrator, or a 
court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will 
be accepted, and no CAIR NO_X Allowance Tracking System 
account will be established for a CAIR unit at a source, until the 
Administrator has received a complete certificate of representation 
under Sec.  96.113 for a CAIR designated representative of the source 
and the CAIR units at the source.
    (e)(1) Each submission under the CAIR NO_X Trading 
Program shall be submitted, signed, and certified by the CAIR 
designated representative for each CAIR source on behalf of which the 
submission is made. Each such submission shall include the following 
certification statement by the CAIR designated representative: ``I am 
authorized to make this submission on behalf of the owners and 
operators of the source or units for which the submission is made. I 
certify under penalty of law that I have personally examined, and am 
familiar with, the statements and information submitted in this 
document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, 
I certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that 
there are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
source or a CAIR unit only if the submission has been made, signed, and 
certified in accordance with paragraph (e)(1) of this section.

Sec.  96.111  Alternate CAIR designated representative.

    (a) A certificate of representation may designate one and only one 
alternate CAIR designated representative, who may act on behalf of the 
CAIR designated representative. The agreement by which the alternate 
CAIR designated representative is selected shall include a procedure 
for authorizing the alternate CAIR designated representative to act in 
lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  96.113, any representation, action, 
inaction, or submission by the alternate CAIR designated representative 
shall be deemed to be a representation, action, inaction, or submission 
by the CAIR designated representative.
    (c) Except in this section and Sec. Sec.  96.102, 96.110(a), 
96.112, 96.113, and 96.151, whenever the term ``CAIR designated 
representative'' is used in this subpart, the term shall be construed 
to include the alternate CAIR designated representative.

Sec.  96.112  Changing CAIR designated representative and alternate 
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec.  96.113. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative prior to the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR source and the CAIR units at the 
source.
    (b) Changing alternate CAIR designated representative. The 
alternate CAIR designated representative may be changed at any time 
upon receipt by the Administrator of a superseding complete certificate 
of representation under Sec.  96.113. Notwithstanding any such change, 
all representations, actions, inactions, and submissions by the 
previous alternate CAIR designated representative prior to the time and 
date when the Administrator receives the superseding certificate of 
representation shall be binding on the new alternate CAIR designated 
representative and the owners and operators of the CAIR source and the 
CAIR units at the source.
    (c) Changes in owners and operators.
    (1) In the event a new owner or operator of a CAIR source or a CAIR 
unit is not included in the list of owners and operators submitted in 
the certificate of representation under Sec.  96.113, such new owner or 
operator shall be deemed to be subject to and bound by the certificate 
of representation, the representations, actions, inactions, and 
submissions of the CAIR designated representative and any alternate 
CAIR designated representative of the source or unit, and the 
decisions, orders, actions, and inactions of the permitting authority 
or the Administrator, as if the new owner or operator were included in 
such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR source or a CAIR unit, including the addition of a new owner 
or operator, the CAIR designated representative or alternate CAIR 
designated representative shall submit a revision to the certificate of 
representation under Sec.  96.113 amending the list of owners and 
operators to include the change.

Sec.  96.113  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR source and each CAIR unit at the 
source for which the certificate of representation is submitted.
    (2) For each CAIR unit at the source, the dates on which the unit 
commenced operation and commenced commercial operation.
    (3) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (4) A list of the owners and operators of the CAIR source and of 
each CAIR unit at the source.
    (5) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR SO₂ and 
NO_X Trading Programs on behalf of the owners and operators 
of the source and of each unit at the source and that each such owner 
and operator shall be fully bound by my representations, actions, 
inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the source and 
of each unit at the source shall be bound by any order issued to me by 
the Administrator, the permitting authority, or a court regarding the 
source or unit.''

[[Page 32749]]

    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a unit, or where a customer 
purchases power from a unit under life-of-the-unit, firm power 
contractual arrangements, I certify that: I have given a written notice 
of my selection as the ``designated representative'' or `alternated 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the source and of 
each unit at the source; and allowances and proceeds of transactions 
involving allowances will be deemed to be held or distributed in 
proportion to each holder's legal, equitable, leasehold, or contractual 
reservation or entitlement or, if such multiple holders have expressly 
provided for a different distribution of allowances by contract, that 
allowances and the proceeds of transactions involving allowances will 
be deemed to be held or distributed in accordance with the contract.''
    (6) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.

Sec.  96.114  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec.  
96.113 has been submitted and received, the permitting authority and 
the Administrator will rely on the certificate of representation unless 
and until a superseding complete certificate of representation under 
Sec.  96.113 is received by the Administrator.
    (b) Except as provided in Sec.  96.112(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
NO_X Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or 
any representation, action, inaction, or submission of any CAIR 
designated representative, including private legal disputes concerning 
the proceeds of CAIR NO_X allowance transfers.

Subpart CC--Permits

Sec.  96.120  General CAIR Trading Program permit requirements.

    (a) For each CAIR source required to have a title V operating 
permit, such permit shall include a CAIR permit administered by the 
permitting authority for the title V operating permit. The CAIR portion 
of the title V permit shall be administered in accordance with the 
permitting authority's title V operating permits regulations 
promulgated under part 70 or 71 of this chapter, except as provided 
otherwise by this subpart.
    (b) Each CAIR permit shall contain all applicable CAIR 
SO₂ and NO_X Trading Program requirements and 
shall be a complete and separable portion of the title V operating 
permit under paragraph (a) of this section.

Sec.  96.121  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
source required to have a title V operating permit shall submit to the 
permitting authority a complete CAIR permit application under Sec.  
96.122 by the applicable deadline in paragraph (b) of this section.
    (b) Application deadline. For any source with any CAIR unit, the 
CAIR designated representative shall submit a complete CAIR permit 
application under Sec.  96.122 covering such CAIR unit to the 
permitting authority at least 18 months (or such lesser time provided 
by the permitting authority) before the later of January 1, 2010 or the 
date on which the CAIR unit commences operation.
    (c) Duty to Reapply. For a CAIR source required to have a title V 
operating permit, the CAIR designated representative shall submit a 
complete CAIR permit application under Sec.  96.122 for the CAIR source 
covering the CAIR units at the source in accordance with the permitting 
authority's title V operating permits regulations addressing operating 
permit renewal.

Sec.  96.122  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR source for which the application is 
submitted, in a format prescribed by the permitting authority:
    (a) Identification of the CAIR source, including plant name and the 
ORIS (Office of Regulatory Information Systems) or facility code 
assigned to the source by the Energy Information Administration, if 
applicable;
    (b) Identification of each CAIR unit at the CAIR source; and
    (c) The standard requirements under Sec. Sec.  96.106 and 96.206.

Sec.  96.123  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec.  96.122.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec.  96.102 and, upon recordation by the 
Administrator under subparts FF and GG of this part, every allocation, 
transfer, or deduction of a CAIR NO_X allowance to or from 
the compliance account of the CAIR source covered by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of 
the CAIR permit with issuance, revision, or renewal of the CAIR 
source's title V permit.

Sec.  96.124  CAIR permit revisions.

    Except as provided in Sec.  96.123(b), the permitting authority 
will revise the CAIR permit, as necessary, in accordance with the 
permitting authority's title V operating permits regulations addressing 
permit revisions.

Subpart DD--[Reserved]

Subpart EE--CAIR NOX Allowance Allocations

Sec.  96.140  State trading budgets.

    The State trading program budgets for annual allocations of CAIR 
NO_X allowances for 2010 through 2014 and for 2015 and 
thereafter are respectively as follows:

------------------------------------------------------------------------
                                             State NOX       State NOX
                  State                     budget 2010     budget 2015
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          67,422          56,185

[[Page 32750]]

Arkansas................................          24,919          20,765
Delaware................................           5,089           4,241
District of Columbia....................             215             179
Florida.................................         115,503          96,253
Georgia.................................          63,575          52,979
Illinois................................          73,622          61,352
Indiana.................................         102,295          85,246
Iowa....................................          30,458          25,381
Kansas..................................          32,436          27,030
Kentucky................................          77,938          64,948
Louisiana...............................          47,339          39,449
Maryland................................          26,607          22,173
Massachusetts...........................          19,630          16,358
Michigan................................          60,212          50,177
Minnesota...............................          29,303          24,420
Mississippi.............................          21,932          18,277
Missouri................................          56,571          47,143
New Jersey..............................           9,895           8,246
New York................................          52,503          43,753
North Carolina..........................          55,763          46,469
Ohio....................................         101,704          84,753
Pennsylvania............................          84,552          70,460
South Carolina..........................          30,895          25,746
Tennessee...............................          47,739          39,783
Texas...................................         224,314         186,928
Virginia................................          31,087          25,906
West Virginia...........................          68,235          56,863
Wisconsin...............................          39,044          32,537
                                         -----------------
    Total Regional Budget...............       1,600,799       1,333,999
------------------------------------------------------------------------

Sec.  96.141  Timing requirements for CAIR NOX allowance allocations.

    (a)(1) By October 31, 2006, the permitting authority will submit to 
the Administrator the CAIR NO_X allowance allocations, in a 
format prescribed by the Administrator and in accordance with Sec.  
96.142(a) and (b), for the control periods in 2010, 2011, 2012, 2013, 
and 2014.
    (2) If the permitting authority fails to submit to the 
Administrator the CAIR NO_X allowance allocations in 
accordance with paragraph (a)(1) of this section, the Administrator 
will allocate CAIR NO_X allowances for the applicable control 
periods, in accordance with Sec.  96.142(a) and (b).
    (b)(1) By October 31, 2009 and October 31 of each year thereafter, 
the permitting authority will submit to the Administrator the CAIR 
NO_X allowance allocations, in a format prescribed by the 
Administrator and in accordance with Sec.  96.142(a) and (b), for the 
control period in the year that is 6 years after the year of the 
applicable deadline for submission under this paragraph.
    (2) If the permitting authority fails to submit to the 
Administrator the CAIR NO_X allowance allocations in 
accordance with paragraph (b)(1), the Administrator will allocate CAIR 
NO_X allowances for the applicable control period, in 
accordance with Sec.  96.142(a) and (b).

Sec.  96.142  CAIR NOX allowance allocations.

    (a)(1) The baseline heat input (in mmBtu) used with respect to CAIR 
NO_X allowance allocations under paragraph (b) of this 
section for each CAIR unit will be:
    (i) For units commencing operation before January 1, 1998 the 
average of the three highest amounts of the unit's annual heat input 
for 1998 through 2002.
    (ii) For units commencing operation on or after January 1, 1998 and 
operating each year during a period of 5 or more consecutive years, the 
average of the three highest amounts of the unit's total converted 
annual heat input over the first such 5 years.
    (2)(i) A unit's annual heat input for a year under paragraphs 
(a)(1)(i), (a)(2)(ii)(A), and (c)(3)(ii) of this section will be 
determined in accordance with part 75 of this chapter, if the CAIR unit 
was otherwise subject to the requirements of part 75 of this chapter 
for the year, or will be based on the best available data reported to 
the permitting authority for the unit, if the unit was not otherwise 
subject to the requirements of part 75 of this chapter for the year.
    (ii) A unit's converted annual heat input for a year specified 
under paragraph (a)(1)(ii) of this section equals--
    (A) The annual gross electrical output of the generator or 
generators served by the unit multiplied by 8,000 Btu/kWh, provided 
that if the generator is served by two or more units, then the gross 
electrical output of the generator will be attributed to each unit in 
proportion to the unit's share of total heat input of such units for 
the year; plus
    (B) For a cogeneration unit, one-half of the unit's annual gross 
thermal energy multiplied by 8,000 Btu/kWh.
    (b)(1) For each control period under Sec.  96.141, the permitting 
authority will allocate to all CAIR units in the State that have a 
baseline heat input (as determined under paragraph (a) of this section) 
a total amount of CAIR NO_X allowances equal to 98 percent of 
the tons of CAIR NO_X emissions in the State trading program 
budget under Sec.  96.140 (except as provided in Sec.  96.142(d)).
    (2) The permitting authority will allocate CAIR NO_X 
allowances to each CAIR unit under paragraph (b)(1) of this section in 
an amount determined by multiplying the total amount of allowances 
allocated under paragraph (b)(1) of this section by the ratio of the 
baseline heat input of such unit to the total amount of baseline heat 
input of all CAIR units in the State and rounding to

[[Page 32751]]

the nearest whole allowance as appropriate.
    (c) For each control period under Sec.  96.141, the permitting 
authority will allocate CAIR NO_X allowances to CAIR units in 
the State that commenced operation on or after January 1, 1998 and do 
not yet have a baseline heat input (as determined under paragraph (a) 
of this section), in accordance with the following procedures:
    (1) The permitting authority will establish a separate new unit 
set-aside for each control period. Each new unit set-aside will be 
allocated CAIR NO_X allowances equal to 2 percent of the 
amount of tons of CAIR NO_X emissions in the State trading 
program budget under Sec.  96.140.
    (2) The CAIR designated representative of such a CAIR unit may 
submit to the permitting authority a request, in a format specified by 
the permitting authority, to be allocated CAIR NO_X 
allowances, starting with the first control period after the control 
period in which the CAIR unit commences commercial operation and until 
the first control period for which the unit is allocated CAIR 
NO_X allowances under paragraph (b) of this section. The CAIR 
NO_X allowance allocation request must be submitted before 
January 1 of the first control period for which the CAIR NO_X 
allowances are requested and after the date on which the CAIR unit 
commences commercial operation.
    (3) In a CAIR NO_X allowance allocation request under 
paragraph (c)(2) of this section, the CAIR designated representative 
may request for a control period CAIR NO_X allowances in an 
amount not exceeding--
    (i) 1.00 lb/MWh for boilers, coal-fired combustion turbines, and 
integrated gasification combined cycle plants, 0.56 lb/MWh for gas-
fired combustion turbines, or 1.01 lb/MWh for all other combustion 
turbines;
    (ii) multiplied by the CAIR unit's heat input for the control 
period immediately preceding the control period for which the 
allowances are requested; and
    (iii) rounded to the nearest whole allowance as appropriate.
    (4) The permitting authority will review each CAIR NO_X 
allowance allocation request under paragraph (c)(2) of this section and 
will allocate CAIR NO_X allowances for each control period 
pursuant to such request as follows:
    (i) Upon receipt of an allowance allocation request, the permitting 
authority will determine whether, and will make any necessary 
adjustments to the request to ensure that the request is consistent 
with the requirements of paragraphs (c)(2) and (3) of this section.
    (ii) On or after January 1 of the control period, the permitting 
authority will determine the sum of the CAIR NO_X allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section) in 
all CAIR NO_X allowance allocation requests under paragraph 
(c)(2) of this section for the control period.
    (iii) If the amount of CAIR NO_X allowances in the new 
unit set-aside for the control period is greater than or equal to the 
sum under paragraph (c)(4)(ii) of this section, the permitting 
authority will allocate the amount of CAIR NO_X allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section) to 
each CAIR unit covered by an allocation request under paragraph (c)(2) 
of this section.
    (iv) If the amount of CAIR NO_X allowances in the new 
unit set-aside for the control period is less than the sum under 
paragraph (c)(4)(ii) of this section, the permitting authority will 
allocate to each CAIR unit covered by an allocation request under 
paragraph (c)(2) of this section the amount of the CAIR NO_X 
allowances requested (as adjusted under paragraph (c)(4)(i) of this 
section), multiplied by the number of CAIR NO_X allowances in 
the new unit set-aside for the control period, divided by the sum 
determined under paragraph (c)(4)(ii) of this section, and rounded to 
the nearest whole allowance as appropriate.
    (v) The permitting authority will notify each CAIR designated 
representative that submitted an allowance allocation request, and the 
Administrator (in a format prescribed by the Administrator), of the 
amount of CAIR NO_X allowances (if any) allocated for the 
control period to the CAIR unit covered by the allowance allocation 
request.
    (d) If, after completion of the procedures under paragraph (c)(4) 
of this section, any unallocated CAIR NO_X allowances remain 
in the new unit set-aside for a control period, the permitting 
authority will reallocate to each CAIR unit that was allocated CAIR 
NO_X allowances under paragraph (b) an amount of CAIR 
NO_X allowances equal to the total amount of such remaining 
unallocated CAIR NO_X allowances, multiplied by the unit's 
allocation under paragr